Lycoming T-53 Gas Turbine Engine Modification for Industrial Application

Gas turbines normally have the rotating and stationary parts. The rotational blades always need clearance to rotation. Blade tip clearance is one of the important parameters affecting performance, safety and stability of a gas turbine engine. However, it is difficult to measure the tip clearance accurately during the tests. The numerical studies are important methods to study the tip clearance effects. Tip clearance effects have been studied for a long time. However, there are still many aspects that are not fully understood and industries still don’t have a good way to perform design with minimum tip clearance losses. In the gas turbine design, the tip clearance considerations are very critical for both performance and reliability. In this paper, we perform the numerical study on the tip clearance impacts during the aerodynamic design, especially the blade loading through blade counts. The study found that the proper blade loading could reduce the tip clearance sensitivity and reduce the tip clearance losses. In the cases of reasonable number of blades, the effect of clearance on the total pressure loss and efficiency had a linear relationship. But in the cases of small number of blades, the effect of clearance on the total pressure loss and efficiency is no longer linear. The study helped turbine designers to consider blade loading and tip clearance together during the turbine design.

At GE Vernova, the newest advanced dry-low NOx (DLN) combustion system for HA gas turbines is the DLN 2.6e. After describing the key enabling features of the DLN 2.6e, this paper focuses on the emissions performance and operational flexibility of the combustion system on the 7HA.03, currently GE Vernova’s most efficient gas turbine in the 60 Hz electric power generation segment. While some full-scale, single-can lab results are presented, the primary focus of this manuscript is the performance on natural gas fuel from the testing of three 7HA.03 gas turbines, one at the GE Vernova full-load test stand and two at a commercial generating facility. The DLN 2.6e is a can-annular, lean premixed combustion system. The advanced premixer at the head end efficiently mixes fuel and air in straight tubes, which are arranged in three fueling circuits. Additionally, the DLN 2.6e system has four axial fuel staging injectors located in the downstream half of the combustion liner, split into two fueling circuits. At high load, the axial fuel stage creates a secondary combustion zone with a substantial fraction of the total energy release and with a low residence time to the combustor exit plane. These features, along with the efficient premixing at the head end, enable the system to achieve below 25 ppm NOx at 15% O2 at the high firing temperatures of the 7HA.03. From full load, the combustor exit temperature may be lowered to attain 5 ppm NOx at 15% O2 before lean blow out occurs. At low loads, the fuel flow to one of the two axial fuel stage circuits may be eliminated, enabling the system to achieve less than 25 ppm NOx at 15% O2 and 9 ppm CO emissions down to near 15 percent of gas turbine full load. 7HA.03 engine data is presented showing low combustion dynamics and little change to emissions when running with cold fuel, representing a 22 percent increase in modified Wobbe index compared to the heated fuel design point. The combustion and control systems support accelerated load ramping. A 7HA.03 gas turbine was demonstrated to progress from ignition to full load in around ten minutes. Finally, the DLN 2.6e has been demonstrated in lab testing to be operable with up to 50% hydrogen by volume in the fuel, and an associated increase in NOx emissions was observed.

The lean, premixed H combustion system was targeted to deliver low NOx and CO emissions from 50% to 100% combined cycle load in both the Frame 7H (60 Hz) and Frame 9H (50 Hz) heavy-duty industrial gas turbines. The H System™ is the first gas turbine combined-cycle technology capable of achieving 60% thermal efficiency. The present paper describes field test performance of the combustion system during the launch and operation of the initial MS9001H installation at Baglan Bay power station near Port Talbot, Wales. The 480 MW 9H combined cycle, fired using the 14-chamber DLN2.5H combustion system, was comprehensively evaluated during the gas turbine Characterization Test program over a period of several months in late 2002 and 2003. Results are reported for exhaust emissions, combustor component durability, operability, and other key combustion system performance parameters over the full gas turbine operating range. The present paper also describes the operability of the H combustion system throughout a rigorous validation of the power plant system, including National Grid Council testing, load rejections, and other key system transients.

In September 1988, a Hitachi-GE model PG5341 gas turbine installed at the Tokuyama refinery of Idemitsu Kosan Co., Ltd. (Japan) successfully recorded 100,325 hours of base load operation over a period of 13 years with 99.4% reliability. The generated power totalled 1,341,770 MWh at the time of final shutdown. The gas turbine, burning Bunker A oil, LPG, and heavy distillate oil, had been the main equipment in a cogeneration plant with a simple heat recovery steam generator using waste heat from the exhaust gas, plus a refired boiler. It was expected that several costly hot gas path components of this turbine would have to be replaced in the near future, and it was not as fuel efficient as more modern designs, so it was decided to replace the PG5341 with a Hitachi H-25 gas turbine. This new model H-25 is designed to have a rated output of 26,200kW and an efficiency of 32.3% (LHV) at the generator terminals under ISO conditions. By the use of a pressure ratio of 14.7 (up from 10.1) and a combustor outlet gas temperature of 1,260°C (up from 980°C), it is expected that efficiency of gas turbine will be improved relatively by 18.7% on a design basis, compared with the PG5341. A factory full-load test of the prototype H-25 gas turbine was completed in August 1988 with excellent results. This machine has been in place and in operation at the Tokuyama plant since the end of November 1988. This is the first commercial application of the Hitachi H-25 advanced gas turbine.

Latest guidelines, novel technical notes, new technical knowledge and recent lessons learned are discussed for emerging market of coal seam gas (CSG) centrifugal compressor trains. Optimum configurations and novel arrangements for coal seam gas (CSG) centrifugal compressor trains driven by gas turbines are addressed. Untreated and saturated nature of CSG need special considerations. Operation, performance, degradation, reliability and maintenance issues of centrifugal compressors, gas turbines, gear units and couplings are also explained. The focus is on new technical knowledge, latest experiences and recent lessons learned on these topics. New recommendations regarding centrifugal compressor train components, gas turbines, machinery arrangement, auxiliaries, gear units, lubrication oil systems, bearings, casing and condition monitoring are also presented. A case study is discussed.

The most effective technologies currently available for controlling NOx emissions from heavy-duty industrial gas turbines are diluent injection in the combustor reaction zone, and lean premixed Dry Low NOx (DLN) combustion. For ultralow emissions requirements, these must be combined with selective catalytic reduction (SCR) DeNOx systems in the gas turbine exhaust. An alternative technology for achieving comparable emissions levels with the potential for lower capital investment and operating cost is catalytic combustion of lean premixed fuel and air within the gas turbine. The design of a catalytic combustion system using natural gas fuel has been prepared for the GE model MS9OO1E gas turbine. This machine has a turbine inlet temperature to the first rotating stage of over 1100°C and produces approximately 105 MW electrical output in simple cycle operation. The 508-mm-dia catalytic combustor designed for this gas turbine was operated at full-scale conditions in tests conducted in 1992 and 1994. The combustor was operated for twelve hours during the 1994 test and demonstrated very low NOx emissions from the catalytic reactor. The total exhaust NOx level was approximately 12–15 ppmv and was produced almost entirely in the preburner ahead of the reactor. A small quantity of steam injected into the preburner reduced the NOx emissions to 5–6 ppmv. Development of the combustion system has continued with the objectives of reducing CO and UHC emissions, understanding the parameters affecting reactor stability and spatial nonuniformities that were observed at low inlet temperature, and improving the structural integrity of the reactor system to a level required for commercial operation of gas turbines. Design modifications were completed and combustion hardware was fabricated for additional full-scale tests of the catalytic combustion system in March 1995 and January 1996. This paper presents a discussion of the combustor design, the catalytic reactor design, and the results of full-scale testing of the improved combustor at MS9OO1E cycle conditions in the March 1995 and January 1996 tests. Major improvements in performance were achieved with CO and UHC emissions of 10 ppmv and 0 ppmv at baseload conditions. This ongoing program will lead to two additional full-scale combustion system tests in 1996. The results of these tests will be available for discussion at the June 1996 Conference in Birmingham.

Solar Turbines Incorporated (Solar), under cooperative agreement number DE-FC26-0CH11049, has conducted development activities to improve the durability of the Mercury 50 combustion system to 30,000 hours life and reduced life cycle costs. This project is part of Advanced Materials in the Advanced Industrial Gas Turbines program in DOE's Office of Distributed Energy. The targeted development engine was the Mercury{trademark} 50 gas turbine, which was developed by Solar under the DOE Advanced Turbine Systems program (DOE contract number DE-FC21-95MC31173). As a generator set, the Mercury 50 is used for distributed power and combined heat and power generation and is designed to achieve 38.5% electrical efficiency, reduced cost of electricity, and single digit emissions. The original program goal was 20,000 hours life, however, this goal was increased to be consistent with Solar's standard 30,000 hour time before overhaul for production engines. Through changes to the combustor design to incorporate effusion cooling in the Generation 3 Mercury 50 engine, which resulted in a drop in the combustor wall temperature, the current standard thermal barrier coated liner was predicted to have 18,000 hours life. With the addition of the advanced materials technology being evaluated under this program, the combustor life is predicted to be over 30,000 hours. The ultimate goal of the program was to demonstrate a fully integrated Mercury 50 combustion system, modified with advanced materials technologies, at a host site for a minimum of 4,000 hours. Solar was the Prime Contractor on the program team, which includes participation of other gas turbine manufacturers, various advanced material and coating suppliers, nationally recognized test laboratories, and multiple industrial end-user field demonstration sites. The program focused on a dual path development route to define an optimum mix of technologies for the Mercury 50 and future gas turbine products. For liner and injector development, multiple concepts including high thermal resistance thermal barrier coatings (TBC), oxide dispersion strengthened (ODS) alloys, continuous fiber ceramic composites (CFCC), and monolithic ceramics were evaluated before down-selection to the most promising candidate materials for field evaluation. Preliminary, component and sub-scale testing was conducted to determine material properties and demonstrate proof-of-concept. Full-scale rig and engine testing was used to validated engine performance prior to field evaluation at a Qualcomm Inc. cogeneration site located in San Diego, California. To ensure that the CFCC liners with the EBC proposed under this program would meet the target life, field evaluations of ceramic matrix composite liners in Centaur{reg_sign} 50 gas turbine engines, which had previously been conducted under the DOE sponsored Ceramic Stationary Gas Turbine program (DE-AC02-92CE40960), was continued under this program at commercial end-user sites under Program Subtask 1A - Extended CFCC Materials Durability Testing. The goal of these field demonstrations was to demonstrate significant component life, with milestones of 20,000 and 30,000 hours. Solar personnel monitor the condition of the liners at the field demonstration sites through periodic borescope inspections and emissions measurements. This program was highly successful at evaluating advanced materials and down-selecting promising solutions for use in gas turbine combustions systems. The addition of the advanced materials technology has enabled the predicted life of the Mercury 50 combustion system to reach 30,000 hours, which is Solar's typical time before overhaul for production engines. In particular, a 40 mil thick advanced Thermal Barrier Coating (TBC) system was selected over various other TBC systems, ODS liners and CFCC liners for the 4,000-hour field evaluation under the program. This advanced TBC is now production bill-of-material at various thicknesses up to 40 mils for all of Solar's advanced backside-cooled combustor liners (Centaur 50, Taurus 60, Mars 100, Taurus 70, Taurus 65, Titan 130, Titan 250 and Mercury 50). This TBC coating system significantly outperformed all other TBC systems evaluated under the program. The initial field unit, with the 40 mil advanced TBC developed under this program, has far exceeded the 4,000-hour requirement of the program, accumulating over 20,000 hours of commercial operation at Qualcomm Inc. in San Diego, CA. The 40 mil advanced TBC remains in excellent condition, with no evidence of chipping or spalling. The engine will continue operation until the unit is due for overhaul at approximately 30,000 hours. The Oxide Dispersion Strengthened (ODS) alloy injector tip testing and evaluation was also successful, however, the ODS injector tip development on this program was terminated, primarily due to the fact that the Mercury 50 injector tip was redesigned (Generation 3) by Combustion Engineering.

This paper presents the results of a study on the influence of the fuel gas composition on the thermodynamic performance of a typical heavy duty gas turbine, followed by an emissions prediction using a chemical reactor network which, in its turn, uses one of the most developed chemical kinetic mechanism for the natural gas combustion. The first part of this work regards a statistical analysis of a time series which shows the fuel gas composition variation along a certain period, revealing the typical concentrations of the gas species. Based on the curves provided by the statistics, several gas compositions were proposed and applied to a thermodynamic model in order to evaluate the impact of the species composition of the natural gas on the gas turbine heat rate and power. Afterwards, several approaches of chemical reactor network were considered in order to choose the methodology that better predicts the temperature and CO and NOx formation within a gas turbine combustor operated at base load regime. Finally, it was studied the influence of the natural gas composition variation over the aforementioned thermochemical properties at the exit of the combustion chamber when considering both operation regime and combustor’s natural gas composition. HE modeling of the combustion systems in transforming energy equipments, such as gas turbine combustors, has many challenges especially concerning to the limitations of the predictive capacity of the models based on the Computational Fluids Dynamics (CFD) and their associated computational cost. Thus, when compared to these more elaborate techniques, models based on Chemical Reactor Network (CRN) allies the low computational cost with the ability to predict pollutant emissions, however, without the descriptiveness of the dynamics of the reacting flow. So, since the advent of the “jet engine”, the modeling based on the CRN approach has been an essential tool in the analysis, design and optimization of practical combustion systems, particularly, with the purpose to ensure an efficient operation coupled to low emissions of pollutants. The CRN approach consists in the resolution of simplified transport equations in order to describe the operation of trivial combustion models such as Perfectly Stirred Reactor (PSR) and Plug Flow Reactors (PFR), which are systematically arranged into a structured scheme with the purpose to represent the combustion process occurring within combustion equipment such a gas turbine combustor. This approach is very useful in the prediction of relevant thermochemical properties as temperature pollutants emissions, which are the most significant parameters in the operation of those equipments. This is the reason why, the choice of a detailed kinetic mechanism that represents the oxidation of any fuel involved in the combustion of gas turbines requires the previous identification of the associated validity range. The principal aim of this work is the determination of the influence of natural gas composition on energetic and emissions performance of an industrial gas turbine. For this purpose, this paper is composed of four sections. In the second section, a linear regression statistical analysis is applied to a data set corresponding to the natural gas composition that is daily provided to an industrial gas turbine installation, in order to establish the variations of each hydrocarbon and the plausible range to be analyzed. Afterwards, a model was built in thermodynamic software in order to estimate the temperature and the pressure values after the combustor, as

A fuel cell—gas turbine hybrid propulsion concept is introduced and initially assessed. The concept uses the water mass flow produced by a hydrogen fuel cell in order to improve the efficiency and power output of the gas turbine engine through burner steam injection. Therefore, the fuel cell product water is conditioned through a process of condensation, pressurization and re-vaporization. The vaporization uses the waste heat of the gas turbine exhaust. The functional principles of the system concept are introduced and discussed, and appropriate methodology for an initial concept evaluation is formulated. Essential technology fields are surveyed in brief. The impact of burner steam injection on gas turbine efficiency and sizing is parametrically modelled. Simplified parametric models of the fuel cell system and key components of the water treatment process are presented. Fuel cell stack efficiency and specific power levels are methodically derived from latest experimental studies at the laboratory scale. The overall concept is assessed for a liquid hydrogen fueled short-/medium range aircraft application. Block fuel savings of up to 7.1% are found for an optimum design case based on solid oxide fuel cell technology. The optimum design features a gas turbine water-to-air ratio of 6.1% in cruise and 62% reduced high-level NOx emissions.

The world is currently undergoing a shift in the power industry with an increase in the amount of electrical power being generated from natural gas. This is being driven, in part, by the increase in availability of natural gas derived from shale gas and the reduction in global natural gas prices. In parallel, there is a second trend; a shift of new gas turbines installations to higher efficiency F and HA-class gas turbine combined cycle platforms. Supporting these industry trends, GE’s DLN 2.6+ combustion system, which is available for the 7F, 9F, 7HA, and 9HA gas turbines offers a high degree of operational and fuel flexibility. The latest evolution of this combustion technology for GE’s 7F gas turbines has been commissioned on 25 units, including new units and upgrades to existing turbines. The increased fuel and operational flexibility of this system is aided by GE’s advanced control systems that includes a high fidelity digital twin. This paper details recent developments of the DLN 2.6+ combustion system as well as validation examples for both the DLN 2.6+ and the digital twin controls system.

Environmental and economic assessment of landfill gas electricity generation in Korea using LEAP model

The advent of dry, low-emissions combustion systems for gas turbine applications and the trend towards requiring emissions monitoring and lower NOx limits by regulatory agencies, have created renewed interests in the uncertainty of NOx emissions measurements. This paper addresses the uncertainty of measuring NOx emissions from gas turbines in the field, including gas turbines equipped with conventional combustion systems, with or without water injection, with dry, low-emissions combustion systems and with exhaust clean-up systems. The sources of errors, using current state-of-the-art instruments, in field emissions testing or continuous emission monitoring of gas turbines to meet specific emission (ppmvd @ 15% O2) as well as mass emission rate (kg/hr) limits are identified. The uncertainty of measuring NOx emissions from gas turbines is estimated and compared with Geld data. The effect of NOx emission levels on measurement uncertainty is also addressed. The minimus NOx measurement uncertainty is determined and is in good agreement with what is currently allowed by regulatory agencies.

Interest in hydrogen as a primary fuel stream in heavy-duty gas turbine engines has increased as precombustion carbon capture and sequestration (CCS) has become a viable option for integrated gasification combined cycle (IGCC) power plants. The U.S. Department of Energy has funded the Advanced IGCC/Hydrogen Gas Turbine Program since 2005 with an aggressive plant-level NOx target of 2 ppm at 15% O2 for an advanced gas turbine cycle. Approaching this NOx level with highly reactive hydrogen fuel at the conditions required is a formidable challenge that requires novel combustion technology. This study begins by measuring entitlement NOx emissions from perfectly premixed combustion of the high-hydrogen fuels of interest. A new premixing fuel injector for high-hydrogen fuels was designed to balance reliable flashback-free operation, reasonable pressure drop, and low emissions. The concept relies on small-scale jet-in-crossflow mixing that is a departure from traditional swirl-based premixing concepts. Single nozzle rig experiments were conducted at pressures of 10 atm and 17 atm, with air preheat temperatures of about 650 K. With nitrogen-diluted hydrogen fuel, characteristic of carbon-free syngas, stable operation without flashback was conducted up to flame temperatures of approximately 1850 K. In addition to the effects of pressure, the impacts of nitrogen dilution levels and amounts of minor constituents in the fuel—carbon monoxide, carbon dioxide, and methane—on flame holding in the premixer are presented. The new fuel injector concept has been incorporated into a full-scale, multinozzle combustor can with an energy conversion rate of more than 10 MW at F-class conditions. The full-can testing was conducted at full gas turbine conditions and various fuel compositions of hydrogen, natural gas, and nitrogen. This combustion system has accumulated over 100 h of fired testing at full load with hydrogen comprising over 90% of the reactants by volume. NOx emissions (ppm) have been measured in the single digits with hydrogen-nitrogen fuel at target gas turbine pressure and temperatures. Results of the testing show that small-scale fuel-air mixing can deliver a reliable, low-NOx solution to hydrogen combustion in advanced gas turbines.

This paper focuses on the use of gas turbines (GTs) equipped with Dry Low Emissions (DLE) combustion technology in offshore oil and gas (O&G) applications. The paper presents information from offshore GT units and discusses improvements in operational reliability and fuel flexibility that have been achieved as a result of extensive testing on combustion systems. These improvements, coupled with significant NOx emissions reductions have made DLE gas turbines a viable alternative to non-DLE gas turbines, the latter of which have traditionally dominated the offshore market. Field operating data will be presented on three lightweight industrial gas turbine models that have been offered with DLE as a standard configuration for over 20 years. Currently, 394 units operate in offshore applications. The DLE configuration has accumulated more than 22 million hours of service. The paper outlines the performance, reliability, and fuel profiles of the current offshore fleet, confirming that DLE combustion systems have now achieved reliability on par with non-DLE combustion systems. A brief review of the testing experience proving the reliability and the range of fuels that can be burned within the DLE system will also be discussed in the paper.

It is important that gas turbines used in Oil & Gas applications can burn a wide variety of fuels with the minimum impact on the environment or project economics. This paper is an introduction for those unfamiliar with gas turbine combustion in any detail into how emissions such as NOx are formed, and how the two most common types of gas turbine combustion system — the ‘conventional’ diffusion flame combustor and the Dry Low Emissions (DLE) combustor operate. There are many types of gaseous and liquid fuels that can be used in Gas Turbines, which can come from a wide range of natural and industrial sources. These different potential fuels are discussed, along with the flexibility of the two different combustion systems to accept different types of fuel. Some of the common contaminants found in these fuels are also discussed, along with the impact these have on the operability and maintenance of industrial and aero-derivative gas turbines, and methods to minimize the impact of these contaminants identified. Finally the paper looks at recommendations on liquid fuel storage to minimize operational issues on liquid fuels.