Patent Application
20220381158
This invention relates generally to combined cycle power generating systems and more specifically, to methods and apparatus for fast starting and loading the heat recovery steam generators (HRSG) of such systems without the use of problematic attemperators and to minimize thermal stress damage to the HRSG superheater and reheater. Thousands of Combined Cycle (CC) power plants are operating throughout the world. In the first fifty years, most were installed as baseload and designed to load to full power in hours to accommodate thermal stress limits of thick wall steam components. The long starting time of these CCs required long gas turbine low power holds necessary to generate low allowable steam temperature from the HRSGs to prevent damaging thermal stress in thick walled components and damaging interferences in steam turbine rotating parts. Although this is a loss of flexibility; as well as increased emissions and fuel costs; it was tolerated since it was only planned for a few starts per year. Operating experience with these CCs demonstrated that even these hold-starting cycles caused most HRSG's component damage, requiring major repairs to many HRSGs; and reduced availability in after only a few hundred start cycles. Problems recorded with HRSGs starting include: superheater and reheater header cracking, tube-to-header weld connection failures, tube buckling, and steam drum cracks. This long history of cycling problems has reduced availability, lowers reliability and increases maintenance costs. Steam turbine components and drums are especially at risk, requiring generating controlled low temperature steam for a long time during starting to minimize thermal stress and maintain adequate clearances in starting, warm-up and loading. Increased installations of renewable solar and wind power often require daily or more frequent starting of critical CC power plants. These new cycling requirements plus: operational, economic and emissions requirements, necessitate loading the gas turbine to full power as fast as possible without a conventional part-load hold for long periods to provide a low exhaust temperature to accommodate steam components. Currently, gas turbines are required to accelerate to full power in 30 minutes or less after overnight shutdown in order to accommodate solar and wind power variability that can cause grid collapse. New once-through type HRSGs eliminate steam drum thermal stress problems and thereby allow the gas turbine to start up and load to full power in 30 minutes. In these HRSGs, high temperature steam generated is bypassed around the steam turbine until generated steam temperature is sufficiently reduced by relatively cool boilerwater sprayed from attemperators to supply the low temperature steam required to start the steam turbine. Current-state-of-the-art HRSGs are started after an overnight shutdown with the high pressure superheater filled with reduced temperature static saturated steam. The gas turbine is motored at start up for many minutes in a purge cycle, pumping cold air to clear possible fuel gas leakage; thereby thousands of pounds of condensate are accumulated in the superheater and reheater bottom headers and tubes. This condensate must be rapidly and completely drained to flash tanks to prevent carry forward when steam flow is initiated to prevent water quench damage to HRSG high temperature components. After flame detection, the exhaust gas rapidly increases in temperature to over 1,100° F. in less than 30 minutes as the gas turbine is rapidly accelerated and fully loaded as fast as possible without a power-temperature hold. Both the superheater and reheater finned thin-walled tubes, filled with stagnant saturated steam, rapidly heat to the exhaust gas temperature with a slight lag. Thereby, many minutes before steam flow is initiated from the evaporator, the superheater and reheater tube temperatures rapidly approach gas temperature hundreds of degrees above the thick-wall headers temperatures that remain cool for many minutes. This causes high differential temperatures and damaging thermal stresses in both conventional natural circulation drum and Benson once-through HRSGs. As a consequence, differential temperatures cause high header and tube joint stresses plus high tube buckling loads. Another problem is that complete draining has often proven to be difficult and partially drained condensate flows forward, quenching hot tubes and causing uneven cooling of tubes which also produces buckling damage due to tube-to-tube differential temperatures and tube joint-to-header cracking. Interstage attemperators are designed to solve these problems by spraying relatively cool boilerwater into the middle of the superheater and reheater to cool the steam and prevent overtemperature. Additionally, terminal attemperators spray low temperature boilerwater into the terminal discharge paths of the superheater and reheater to reduce the steam temperature to the allowable temperature required by the Steam Turbine Stress Controller as it controls starting the steam turbine. The effectiveness of attemperators is dependent on high velocity steam flow to assist in atomizing, mixing and evaporating the injected water mass flow spray which must be accurately controlled. For advanced rapid starting CCs, typically four attemperators using copious quantities of relatively cool boilerwater flow rates are required to generate the cooling steam flow to limit over-temperature damage of the superheater or reheater and to supply turbine starting steam at a much lower allowable steam temperature than the conventional HRSG generates with the gas turbine at full load. U.S. Pat. No. 7,621,133 METHODS AND APPARATUS FOR STARTING UP COMBINED CYCLE POWER SYSTEMS granted to one of the world's largest manufactures of steam turbines, describes the method it has installed in many CCs for rapidly accelerating to full power; whereby the steam produced with conventional HRSG superheater and reheater uses two terminal and two interstage attemperators in the HRSG to generate allowable low temperature steam at 700° F. in the patent example (or slightly above the steam turbine's measured bowl metal temperature when starting) to start the steam turbine. As described in U.S. Pat. No. 7,621,133, attemperators are now installed in fast start combined cycles to spray large quantities of relatively cool water into the high pressure superheater and reheater steam paths to generate 700° F. steam with the gas turbine maintained at full power. This temperature is necessary to control the steam turbine stresses and clearances in the starting for the many minutes while the gas turbine is maintained at Full Load power. Additionally, at low power demands to prevent many additional forced steam system shutdowns the attemperators are employed to cool the steam generated at low gas turbine power. At the low operating power, exhaust gas flow is reduced on many turbines and exhaust gas temperature increases, causing excessive tube metal to temperature. Attemperator water sprays prevent over temperature of tubes and thereby prevent many life reducing and expensive CC forced shut downs. The attemperators have a problematic operational history with reported damage including: over-spray water quench, and thermal differential damage of tube buckling and joint cracks in superheater and reheater HRSG components, resulting in high thermal stresses reducing life and over-spray steam turbine water ingestion damage.
Basic changes and innovative systems and methods have been introduced to obtain design solutions for these HRSG starting problems. The current changes concentrate on solving the thick wall drum stress problems, as well as the tube-to-thick wall header connection failures. High pressure drum, superheater and reheater header materials have been upgraded to higher strength alloys. Reduced diameter and reduced wall thickness drums described in recently patented systems use a two-stage method of steam separation. They use eight vertical secondary vertical steam separator bottles welded to the top of a reduced diameter high pressure drum made of higher strength steel and are operating in newly commissioned HRSGs. The additional eight separators are designed to eliminate boilerwater liquid spray and chemical carry-over from the confined spaces of the reduced diameter main horizontal drum. Another approach is to eliminate the high pressure drum entirely by using a patented once-through Benson forced flow evaporator circulating system; using high purity feedwater with low dissolved solids. The Benson design has two evaporator sections that use vertical heat transfer tubes with forced flow evaporation modified by natural circulation in vertical tubes to match the tube row heat flux. Between the first and final evaporator, a two-phase flow distributor is installed to produce a more uniform steam water mixture entering the final evaporator designed to produce superheated steam. Steam from the final Benson evaporator passes through a steam separator mounted externally of the HRSG casing. This separator is designed to ensure dry steam is conducted into the superheater sections of the HRSG in starting. The steam separator is normally employed during starts to separate swellwater and spray from the steam. During normal operation of this type HRSG, the separator is dry since the final evaporator is designed to produce superheated steam. Both of these HRSG configurations are specially designed to meet fast start specifications, but they result in extra complications, possible parallel flow boiling instability with additional steam pressure loss and expense. The superheater and reheaters are uncooled in both modifications during starting until the attemperators introduce cool boilerwater spray to protect the tubes. Another limitation of the Benson and reduced diameter drum HRSG start solutions is they both incorporate the relatively rigid thermal harp heat exchanger in their heat transfer modules. Thermal harps are fabricated in a factory into transportable modules and assembled as an HRSG on site, totaling thousands of approximately 50-to-80 feet tubes, with each tube end welded to thick headers at the top and bottom of each vertical tube. This relatively rigid structure has been generally acceptable for base load power plants. Fast start and cyclical service has required redesigns of thermal harps to reduce rigidity, particularly for the superheater and reheater. New cyclical service HRSGs are generally constructed with only one row of tubes per header connecting to critical hot headers to reduce header diameter, thickness and stress. One of the main reasons for the bottom headers is to drain water. Historically in starts, condensate quench failures of tubes, joints and headers have been traced to inadequate draining of bottom headers. The fast starting designed harps use three large pot drain valves per high temperature bottom headers to account for header thermal bow distortion. These drains are controlled automatically with large capacity water sensing drain pots or equivalent. With bundles redesigned for fast start, only one row of tubes per header is used per harp, whereby lower headers are free to expand downward, accommodating the average expansion of a single row of tubes to minimize damage. Although this does not eliminate tube-to-tube differential expansion or tube-to-thick header differential temperature stress, the single row header reduces the high calculated stresses due to differential temperatures between two or more tube rows connected to the same header.
The design fixes described above are incremental improvements to resolve specific drum, header-tube thermal stress and drain problems caused by conventional fast starting methods. However, the design fixes don't solve the many problems of: thick wall header-to-tube differential thermal stress and the means to control starting temperatures without problematic attemperators, and incomplete draining causing carryover quenching of hot tubes. A part of the solution to reduce thermal stress in starting is the once-through HRSG without drums and most headers. An exemplary HRSG of the once-through type with vertical tubes is described in U.S. Pat. No. 8,820,078 HEAT RECOVERY STEAM GENERATOR AND METHOD FOR FAST STARTING COMBINED CYCLES, which is incorporated herein by reference. This patented once-through configuration with vertical tubes is not in operation in large HRSGs at present. However, more than 200 once-through HRSGs with horizontal tubes are currently installed around the world. They have a patented once-through flow path. U.S. Pat. No. 4,989,405 COMBINED CYCLE POWER PLANT describes the flow path and basic configuration of the more than 200 once-through HRSGs are in operation. These HRSGs have a unique start method; they start completely dry, with feedwater introduced into the economizer header after flame detection. These operating HRSGs substantiate the patented basic once-through flow path of identical parallel serpentine circuits; wherein a feedwater flow rate controller regulates the HRSG output steam temperature by balancing output steam energy to the input energy of the exhaust gas. The feedwater flow rate controller uses measured gas turbine parameters and steam temperature feedback to correct for degradation in the gas turbine and the heat transfer factors. The feedwater is directed through an orifice in each economizer tube for uniform flow and to stabilize parallel flow boiling and controlled temperature steam discharges from the superheater. Their typical current application is less than 70 MW combined cycle power plants and are constructed using horizontal tubes that are self-draining. Large utility HRSGs (a main application disclosed herein) require approximately ten times larger heat transfer area compared to the 70 MW once-through HRSGs. Structural criteria, gas flow path and costs to mechanically support thousands of tons of sliding horizontal heat transfer tubes justify use of top-supported vertical pendent tube once-through HRSG configurations as an economic solution for large HRSGs. However, vertical tube once-through circuits are not drainable. U.S. Pat. No. 8,820,078 describes a simple pressurized air blowdown drain and drying system. This system only requires two valves to drain and dry the HRSG for maintenance, freeze protection or layup with vertical tubes. Whereby the numerous: pot drain valves, headers and complex drain pipes that reduce expansion flexibility required in conventional HRSGs are eliminated. Conventional gravity draining dozens of bottom headers (each with three drains, plus rigid piping) often results in reliability problems to completely drain and dry the conventional HRSGs. The simple two-drain-valve, dry air blowdown system results in fast and complete draining and air flow drying plus nitrogen blanketing. A simple two-valve nitrogen blanketing system is also described in U.S. Pat. No. 8,820,078 for long weekend shut downs using an automatic nitrogen blanketing system (such as nitrogen membrane generating systems) for corrosion protection when steam pressure falls below 5 psig.
The exemplary once-through HRSG flow path is fabricated entirely of tubes arranged in separate identical serpentine flow path circuits assembled in parallel circuits for each pressure level. U-tubes connect long vertical finned tubes at the top and bottom in a serpentine flow path without intermediate headers, completing an all tubular flow path between the inlet and outlet headers and forming a complete circuit. Starting at the economizer inlet header, water passes through a flow restrictor at the inlet of each circuit to distribute flow uniformly between circuits and prevent parallel channel boiling instabilities. From the economizer, water flow goes through a connecting tube to a tubular evaporator, discharging from it directly to the tubular superheater and its outlet header. The serpentine tubular flow path from the economizer header through to the superheater header is without headers in-between. Feedwater flows from the economizer header through the first inlet row tube and through the economizer through a single flow path to the last row of the superheater header. Different HRSG sections often incorporate various tube diameters and fin configurations for optimum design criteria. By assembling 20 or 30 circuits in parallel, a module is assembled to facilitate transportation. Several modules complete a once-through HRSG for CCs when supported and connected in the casing. Evaporation typically takes place approximately at the middle of each circuit in normal operation (without a drum or separator). Depending on operating conditions, the evaporation function can be located anyplace in the circuit to optimize performance (for example: optimization for extreme ambient air temperature or maximum efficiency at low power). Most of the HRSGs of the once-through type in operation start dry, without boilerwater in any of the tubes, and evaporation initiates in the first rows of the economizer during starting, providing cooling steam flow. In operating mode, the once-through HRSG utilizes a predictive control method to set the feedwater flow to the generated steam energy to match the input gas energy flow rate. In this control method described in U.S. Pat. No. 5,237,816 STEAM GENERATOR CONTROL SYSTEM, the thermal energy entering the once-through HRSG is calculated by the controller from the gas turbine's measured parameters at measured ambient air temperature and known turbine characteristics. The input gas energy to the HRSG predicts and sets the feedwater flow (and thereby the steam flow) to match the CC's known parameters to produce maximum steam power output at any power from part load through full power of the gas turbine. The water flow rate is set immediately and feedback flow is measured in a fast-response feedwater flow control loop. Concurrently, the slow-lagging measured output steam temperature and pressure are used as feedback to provide required trim corrections to the actual water flow rate to account for turbine degradation, heat exchanger fouling, leakage and other factors modifying the computer calculated predictive steam flow rate. This method of control has been proven to have high response in the operating once-through HRSGs and is installed on many smaller combined cycles that often require rapid transient response. Many once-through type HRSGs are installed with LM6000 gas turbines with a horizontal HRSG tube orientation supported by tube sheets. Tubes in most installed once-through HRSGs are made of alloy Incoloy 800: a high nickel (˜30%) and high chromium (˜20%) high temperature and corrosion resistant tube (the fins are typically carbon steel). This expensive alloy is competitive in small HRSGs for many reasons, including: dry operation at full gas turbine power, dry starting, self-draining, corrosion protection and simple water treatment. In small HRSGs, material costs are a relatively lower fraction of the total installed cost. Large utility HRSGs require approximately ten times the tubing of the small once-through type HRSGs. For large utility CCs as disclosed herein, the expensive alloy cost is not economic or necessary for large CC operating specifications. Operating experience with Benson type once-through HRSGs substantiates the use of “standard carbon steel tubes” when operating with full flow condensate polishing and all volatile water treatment for large utility type HRSGs.
The mechanical design problem of supporting hundreds of tons of horizontal finned tubes (as they expand and slide across many expensive thick tube sheets) needs a different solution: a top supported vertical tube arrangement. Top supported vertical tubes, where the massive weight is carried by flexible hanger rods in tension for each circuit for maximum flexibility, is well matched for large HRSGs. One innovative arrangement is described in U.S. Pat. No. 6,019,070 CIRCUIT ASSEMBLY FOR ONCE-THROUGH STEAM GENERATORS. It describes an innovative mechanical configuration for a large vertical tube once-through HRSG fabricated with “carbon steel” tubes (tubes of standard ASME carbon and low alloy steel tube specifications used in conventional HRSGs). The long vertical finned heat transfer tubes are arranged in a continuous serpentine flow path, with the tubes connected by U-bends or longer jumper tubes to form a series of modules each with matching individual circuits. Typically, each tube end is connected to a tubular U-bend connected to the next tube row with a computer controlled orbital welding machine to the vertical finned tubes in a factory for quality control. Rigid thickwall headers are not used in order to provide maximum flexibility between tubes and circuits. The tubular circuits in parallel are welded to an inlet economizer header and form an economizer module, and jumper tubes are connected in the field erection to evaporator modules; jumper tubes in turn connect the outlet of the evaporator to the superheater bundle circuit modules connected to the superheater outlet header to form a multi-module complete once-through HRSG. Full-flow condensate polished deionized (DI) feedwater is required, combined with all volatile pH control with deaeration; as used in many operating Benson once-through HRSGs, and similar water treatment is used in many large supercritical steam power plants installed around the world. The latest developments in RO, membrane oxygen control and membrane carbon dioxide control also are well matched to the frequent starting CCs to minimize boilerwater chemical upsets in fast cycling units.
In one aspect, a method for fast starting the HRSG of a combined cycle (CC) power generation system is provided to reduce thermal stresses in the HRSG high pressure superheater and reheater; and generate low temperature steam to start the steam turbine without attemperators. The method includes loading the gas turbine at a maximum rate, and maintaining the temperature of the high pressure and hot reheat steam supplied to the steam turbine at the substantially constant lower allowable starting temperature of 700° F. (in this example) from initial steam admission into the steam turbine until all the steam generated by the HRSG is admitted; which enables optimum loading of the steam turbine to criteria from the Steam Turbine Stress Controller; and at the same time protecting the high pressure superheater and reheater components from overheating and thermal stress damage.
In another aspect, a system for starting and loading a CC power generation system is provided. The system includes a gas turbine and a steam turbine. The CC system further includes a once-through HRSG which supplies steam to the steam turbine, a condenser connected to the steam turbine, and bypass paths used in starting from the HRSG around the high pressure steam turbine section to the cold reheat steam line. In addition, the flow path through the reheater into the intermediate pressure manifold which has a bypass around the intermediate steam turbine to the condenser used in starting. The intermediate pressure manifold also has a flow path to a normal admission valve to the intermediate steam turbine used for normal CC operation. Further, a second admission bypass start-up admission valve around the high pressure steam turbine section conducts HRSG high pressure steam directly to the intermediate pressure steam turbine section. Also, the method utilizes a once-through HRSG equipped with a unique HRSG start-up apparatus and circuit drain system to enable a wet starting method to produce steam faster than conventional systems while also reducing damaging thermal stresses. The HRSG start-up apparatus accurately positions boilerwater level in the top of each last row superheater tubes. The wet starting method is initiated with the superheater last row tubes filled with saturated boilerwater. Whereby as the gas turbine accelerates and is loaded to Full Speed No Load and Full Speed Full Load at a maximum rate, the wet starting method controls the dryout zone in the superheater by a start-up boilerwater level controller. In this method the high pressure superheater generates a gradual ramp-up in steam temperature from saturation temperature to dry steam at an allowable superheat temperature for starting the steam turbine at 700° F. Whereby the HRSG tubes do not overheat and differential thermal stress between header to tubes is minimized. Conventional steam temperature control by attemperators spraying relatively cool boilerwater into hot components is eliminated; thereby reducing thermal cycling damage while reducing possible steam turbine water ingestion. The method includes loading the gas turbine to full load at its fastest rate, maintaining the temperature of steam to high pressure and intermediate pressure sections of the steam turbine at substantially constant low superheated steam temperature (700° F.) from the initial steam admission to the steam turbine until all of the steam generated by the HRSG is admitted, while modulating flow of steam through the bypass paths so as to control the high pressure and intermediate steam pressure. After all steam flow is admitted to the steam turbine at a low starting temperature, the steam temperature to the high pressure section and intermediate steam turbine section is increased to full rated load steam turbine temperature and flow by adjusting the dryout zone position through the superheater and into the evaporator until the dryout zone is in its normal position in the evaporator. The temperature increase rate is controlled by the HRSG feedwater flow controller to adjust steam temperature rise rates to the setpoint criteria from the Steam Turbine Stress Controller element of the steam turbine. This method is also employed to prevent over-temperature of tubes at low load CC operation to cool high temperature steam, replacing problematic attemperators.
While the starting methods and apparatus described herein are in the context of a combined cycle used in an electric utility power generation environment, it is contemplated that the method, apparatus, teachings and principles described herein may find utility in other applications such as: cogeneration, industrial HRSGs, and gas turbines using a variety of combustible fuels, including but not limited to natural gas, liquid fuels and green hydrogen. In addition, such starting methods can be utilized in connection with both multi-shaft and single-shaft combined cycle systems. Multiple reheaters and supercritical pressure HRSGs are also well accorded the benefits derived from the described apparatus and methods. The description herein below is therefore set forth only by way of illustration, rather than limitation.
In normal rated power CC operation, superheated steam is conducted from the high pressure superheater header 14 through the header discharge nozzle 9 to the high pressure steam manifold 10 and then through the main steam piping system to the high pressure steam turbine admission valve 48 of the high pressure steam turbine HP. After extracting work in the high pressure turbine, lower temperature and pressure steam is discharged through a one-way valve and mixed with steam from the intermediate pressure steam generator (IPSG) discharge valve 45. Both steam flows enter the cold reheater headers and flow through heat transfer tube rows illustrated in dash line paths to be discharged into the hot reheater header 3. From the hot reheater header 3 steam is conducted into intermediate pressure manifold 7 conducting the steam to the normal intermediate turbine admission valve 47. Other steam turbine valves are elements supplied as part of the steam turbine manufacturer and are illustrated by steam valve arrangement SCV (STOP-AND-CONTROL VALVES) that includes the trip-stop and control valves. These valves are manipulated in starting by the Steam Turbine Stress Controller (STSC) for: steam flow, temperature and pressure control; and to control steam turbine casing and rotor metal temperature differential change rates, as well as rotor speed, and transmit starting steam setpoint temperature inputs to the feedwater flow rate controller 88 to regulate the steam temperature in the starting method.
To better illustrate the unique high pressure system's starting method for a HRSG with at least the high pressure system configurated with a once-through flow path; the low pressure system and intermediate pressure HRSG system's starting methods are not described in detail since they can be started with conventional methods. Standard safety valves, drains, vents gages and other standard steam components are not shown to clarify the invention.
The start-up apparatus 1 enables a wet starting method in which the high pressure superheater is filled with warm boilerwater is at a saturation pressure of at least 35 psig; whereby the superheater and reheater do not overheat as in starting conventional HRSGs with dry stagnant steam in the high pressure superheaters. The start-up apparatus ensures each last row superheater tubes starts equally filled with the same volume of boilerwater; and as the gas turbine starts to accelerate, the water level in the tubes is controlled as tubes gradually ramp-up from saturated boilerwater temperature to generate low temperature dry steam required for starting the steam turbine while the gas turbine is at full power with turbine exhaust greater than 1100° F. for many minutes.
The start-up apparatus 1 is primarily a horizontal arrangement of pipes that provides a means to control the boilerwater levels when starting in combination with the unique circuit drain system components 13, 63 and 16. The apparatus also provides surge expansion volume attached closely to each superheater header for swellwater management in the starting method. The start-up apparatus 1 is fabricated of relatively small diameter pipes compared to the main steam manifold 10, these pipes providing a means to place the HRSG in a “ready to start status,” and thereby enabling: filling and controlling the water level in the high pressure superheater last tube rows 2, managing starting surge, draining swellwater and controlling temperature and pressure in starting. The start-up apparatus 1 is illustrated in
The last rows of the high pressure superheater tubes 2 are shown in the lower right corner of
A warm starting method is described in detail in the next paragraph. Cold and hot starts are similar, with minor differences described in following paragraphs. In each starting method, the HRSG is placed in a: “ready to start status.” The HRSG after shutdown is bottled up to maintain as high a warm starting temperature as possible in preparation for a fast starting method to minimize thermal shock and minimize starting time. In warm starts, typically after an overnight shutdown, the superheater 2 contains stagnant saturated steam at a few hundred degrees F. after spin-down cooling and hours of HRSG heat loss plus cooling from motoring the gas turbine to purge possible explosive gasses from the HRSG. The saturated boilerwater is primarily located in the evaporator circuits 26 and is below normal operating temperature but typically more than a hundred psig when starting warm. Prior to starting, condensate from the condenser hotwell or feedwater makeup tank is pumped through the feedwater treatment system 30 and is pumped through the feedwater heater FW to feedwater pump 4 and through the feedwater control valve 15 to economizer inlet header 5. Whereby feedwater is distributed uniformly into each circuit by inlet restriction 65 at each circuit's first row economizer tube's inlet. The feedwater flow into the individual once-through circuit displaces boilerwater from each economizer circuit tube directly into the corresponding tube in the evaporator 26 section of the circuit of the continuous serpentine flow path; boilerwater flow in turn then displaces the saturated water in the evaporator section; forcing flow into the superheater tubes and filling them through the last superheater row 2 tube in each circuit. Boilerwater flow is continued through each last row 2 until all the superheater headers 14 are filled with saturated boilerwater from the evaporator 26 tubes. Pumped boilerwater flow sequentially is continued from the superheater header 14 and into the start-up apparatus 1 being pumped vertically through the header discharge nozzle 9 through the horizontal drain pipes 11 discharging into and filling the horizontal drain manifold 8, wherein the two pot drain valve systems 20 at each end of the horizontal drain manifold 8 are signaled to remain shut and thereby prevent evacuating the water during the filling procedure. The horizontal drain manifold 8 fills with saturated boilerwater until level sensor element (LE) 21 signals the feedwater control valve 15 to close. Thereby placing the water in the upward vertical loop section of the horizontal drain manifold 8 (
The starting method for the warm HRSG is initiated by the gas turbine flame detection signal 91 FD that is transmitted to start-up boilerwater level controller 100 (
The starting method is to maintain the last tube row 2 and header 14 at approximately boilerwater saturation temperature during the initial acceleration of the gas turbine to reduce thermal stresses and generate dry steam earlier than conventional HRSGs. Thereby preventing the damaging differential temperatures between the thin tubes that rapidly go to gas temperature and the temperature lagging colder thick headers in conventional HRSG dry starts. Acceleration time to Full Speed No Load is typically 7 minutes as referenced in the background and is used in this description. The circuit drain valve 16 flow rate coefficient Cv is selected to enable draining the final two rows of the high pressure superheater in 7 minutes of the volume of water in tubes VTOT (the two rows where the exhaust gas enters the HRSG). The lowest drain forcing pressure in a cold HRSG is used to select drain valve 16 flow rate coefficient. When cold, a corrosion protecting nitrogen blanket at a pressure of at least 5 psig is applied by nitrogen supply valve 27, see
The volume of boilerwater 82, VTOT see
V
TOT
=t·C
v·(FRwarm)(PHP)1/2 (1)
V
TOT
=t·C
v·(FRcold)(Pnitrogen)1/2 (2)
At flame detection 91 FD, boiler water level controller 100 opens circuit drain valve 16 and its flow ratio rate FRWARM is adjusted by the measured steam pressure 80 PHP in the HRSG 25 superheater as the gas turbine starts to accelerate to Full Speed No Load. Thereby as the rotor speed, gas temperature and exhaust gas flow rate are increasing, the boilerwater dryout zone simultaneously retreats through drain valve 16 from the high pressure superheater header 14 toward the bottom of row 2. In this process; boiling swellwater wets and initially maintains both the headers and tubes at saturated boilerwater temperature, and as the exhaust gas temperature and flow rapidly continues to increase; steam flow is generated through the last superheater row 2 and flows into start-up apparatus 1. Pressure is controlled by control valve 12 that gradually ramps the initial pressure to a higher saturation pressure, to minimize thermal stress between the thick header and thin tubes. As steam and swellwater are discharged through the header (heating it), and the tubes are cooled to swellwater temperature in the initial starting transients at the critical header joint. Concurrently, swellwater in the dryout zone of tubes is drained away from the superheater headers 14 toward evaporator section 26 of the HRSG as swellwater and heated boilerwater is conducted into upstream superheater tubes and vaporizer tubes by means of boilerwater backflow through circuit drain valve 16. Concurrently, wet steam and carryover swellwater are also discharged from the header 14 into start-up apparatus 1 heating header 14 while cooling tubes in row 2. Carryover swellwater mainly collects in the horizontal drain manifold 8 and as the pot drain valve systems 20 sense water they automatically open to drain swellwater to a flash tank 17 and automatically close when swellwater is no longer sensed to prevent the loss of steam. The system surge volume includes the drained superheater last two tube rows and headers 14, horizontal drain tubes 11, horizontal drain manifold 8 and a larger expansion volume in the start-up apparatus downstream of the loop barrier contained in the downward leg volume shown as: L=VOL of the steam discharge line to the pressure control valve 12 near ground level (see
At the programed seven minutes to Full Speed No Load, or when high pressure steam flow is sensed at 700° F. by controller 100 set point switch 81 THP, the start-up boilerwater level controller 100 commands circuit drain valve 16 to close. This event also signals the feedwater flow rate controller 88 (see
At Full Speed No Load the gas turbine is loaded as fast as allowable to full load and the exhaust gas temperature ramps up to approximately 1100° F. in 15 to 20 minutes. As the gas temperature increases controller 88 maintains the high pressure steam increasing discharge flow at the low allowable starting temperature 700° F. by increasing high pressure feedwater flow (see next section). The Steam Turbine Stress Controller (STSC), using sensors in the steam turbine measuring metal temperatures, pressures and other parameters manipulates steam turbine stop control valves SCV to control starting rates of the intermediate pressure steam turbine IP section and the high pressure turbine HP section. Concurrently the high pressure turbine bypass valve 46 is modulated closed. At full gas turbine load total high pressure steam flow is approximately 120% rated flow due to the lower outlet temperature 700° F. being generated for starting the steam turbine. Steam flow rates may be adjusted to approximately 60% of rated turbine flows through the high pressure section admission valve 48 and intermediate pressure section start-up admission valve 49 (the flow splits depend upon specific steam turbine design). At full gas turbine load the steam turbine is loaded as fast as safely allowable to full rated power. The high pressure steam temperature is increased by the setpoints generated by the STSC to the feedwater controller 88. Reheater hot header 3 flow is from of the increasing exhaust temperature of the high pressure turbine HP. Additionally, the gas temperature flow from the high pressure superheater is also rapidly increasing the intermediate pressure steam temperature from reheater header 3 flow into manifold 7. As temperature increases to 700° F. in steam discharge from header 3 it is then conducted through the normal admission valve 47 and mixed with flow from the intermediate pressure turbine start-up admission valve 49. The high pressure superheater header 14 temperature setpoints are increased from 700° F. to load the steam turbine by adjusting the dryout zone in the superheater to corresponding increasing exhaust gas temperature by feedwater controller 88. Thereby at a safe rate established by the Steam Turbine Stress Controller the high pressure steam temperature setpoints to feedwater controller 88 are increased to full rated steam turbine temperature and flows at a rate and flow to the steam turbine at acceptable stresses and other parameters. At full gas turbine load; feedwater flow controller 88 adjusts the dryout zone position from the high pressure superheater to its normal position in the vaporizer 26. Thereby Full Load steam temperature of typically 50 F degrees less than the gas turbine's exhaust gas temperature can be obtained within approximately 20 to 50 minutes depending on the design of the steam turbine. This permits Intermediate steam turbine normal admission valve 47 to be controlled fully opened as intermediate steam turbine start-up valve 49 is synchronized closed when the steam turbine is fully loaded with the steam admission valves 48 and 47 fully opened and as the steam system pressure control bypass valves 31, 46 and 12 are manipulated to maintain steam pressures during loading of the steam turbine to full rated load by providing alternative flow paths. The STSC manipulates the steam turbine SCV control valves in loading the steam turbine to full power load without attemperators spraying cool boilerwater into hot superheater and reheater components. At full rated power steam valves to turbine are fully open and all bypass valves fully closed; and at the normal CC operating condition of the throttle pressure sliding up or down as HRSG steam generation varies in operation.
The dryout position is controlled by adjusting the total flow of feedwater WFWTOT signal to regulate feedwater flow control system 150 that regulates feedwater valve 15 and high pressure feedwater pump 4 VFD motor to obtain the high pressure steam superheater temperature THP for the TSET POINT calculated by the Steam Turbine Stress Controller.
W
FW·(CPFW·ΔTFW+hfg)=Wgas·Cgas·ΔTgas (4)
Where:
Certain parameters were established to optimize the controller function. One is the temperature of gas discharging from the high pressure economizer tube rows as 280° F. Thus, ΔTgas=Tgas−280° F., where Tgas is a measured parameter of the exhaust gas of the gas turbine. The specific heat of the gas and the water-steam are assigned average values of: Cgas=0.25 and CPFW=0.68. The feedwater inlet temperature Tin to the high pressure steam economizer at rated full gas turbine power is set at 240° F. from FW heater and low pressure steam generator evaporator. With the foregoing, the high pressure feedwater flow is as follows:
W
FW
=W
gas·(Tgas−280° F.)·Cgas/CPFW·(THP set point−240° F.)+hfg (5)
The heat of vaporization is relatively constant and is replaced by an assigned value of hfg of 950 btu/lb. As CPPFW and Tin are relatively constant and replaced as shown below. Thus, with all assigned values substituted, the high pressure feedwater flow control algorithm becomes;
W
FW
=K·[0.25Wgas·(Tgas−280° F.)/0.68·(THP setpoint−240° F.)+950] (6)
Correction factor K reduces flow to correct for intermediate steam generator reductions in gas temperature and plus deviations of the assigned values causing errors in the predictive open loop algorithm. These error causing factors are corrected by the high gain closed loop temperature Proportional and Integral PI Controller 110 that corrects for calculation approximations and other factors.
In the closed loop mode of superheater control, a corrected feedwater flow rate and a Closed Loop Correction Factor (WCLCF) are generated in accordance with the equations:
FW
TOTAL
=W
FW
+W
CLCF (7)
and,
W
CLCF=(THP set point−THP)GCLCF (8)
The steam output temperature THP is measured for example by thermocouple well and summed in adder 108 with THP setpoint from Steam Turbine Stress Controller (STSC). This produces an error signal which is converted by a conventional Proportional and Integral PI controller 110 to a control signal compatible with that generated by calculation block 118. The latter signal is summed with the predictive feedwater flow (WFW) signal in adder 114, producing the corrected feedwater command signal (WFWTOTAL) for a command signal to the feedwater system controller 150. Controller 150 is a PLC, a standard Programmable Logical Controller including Proportional and Integral PI Controller functions that integrate the systems to operate feedwater control valve 15 and the high pressure feedwater pump 4 VFD drive motor to optimize pumping efficiency into the HRSG 25. Feedwater system controller 150 also employs a closed loop PI feedback signal from the flow meter 50 downstream of valve 15 to correct the flow for leakage, wear and cavitation erosion of components.
Throughout the above starting method protecting the superheater from high thermal stress, the reheater is also started to minimize the reheater thermal starting stresses. The superheater functions as a protective evaporator heat transfer screen; greatly reducing the gas temperature entering the reheater tube rows immediately downstream of the final rows of the superheater. The reduced gas temperature is however sufficiently elevated to evaporate condensate which is uniformly distributed and accumulates at the bottom of each reheater U-tube after shutdown cooling. The flame detection signal is employed to connect the reheater to the vacuum in the condenser by opening intermediate steam turbine IP bypass valve 35. Thereby the condensate in the bottom portion of the numerous U-tube studs has relatively high area for being heated by hot exhaust gas above the boiling temperature at vacuum for seven minutes as the gas turbine is accelerating and thereby evaporating much of the condensate. Additionally, reheaters do not have bottom headers having relatively low gas flow surface area to evaporate pools of collected condensate as in conventional reheaters. As a consequence, small volumes of condensate in each tube, if remaining, with relatively high tube surface area when sprayed upward by steam flow and exposed to the high heating rate in the finned section, will rapidly evaporate without causing water slugging damage as steam flow is initiated. This minimizes the documented problematic draining and water slug quench damage history of reheaters in starting of conventional HRSGs. Also eliminated by this method is the thermal expansion stresses due to bottom headers and their rigidly connected drain piping restraint stresses.
The feedwater flow controller 88 described above for starting is also employed, as in operating to optimize CC performance in extremes of ambient air temperatures and, to reduce the high pressure steam temperature THP when the gas turbine is operated at low-load. At low-load in many gas turbines, gas flow WGAS is reduced by inlet guide vanes 95 position to improve part load efficiency. A mass flow decrease causes the exhaust gas 90 TGAS to increase, resulting in higher superheater and reheater steam temperatures. Tube metal temperatures may exceed design allowance due to reduced cooling and therefore steam temperature must be reduced to prevent damaging loss of component life. In conventional combined cycles the attemperators discussed earlier are used to cool the high pressure superheater and reheater steam temperature by spraying relatively cool boilerwater into relatively low steam flow interstage pipes risking overspray thermal shock. The problematic attemperator systems are replaced by controller 88 adjusting the dryout zone from the evaporator 26 into the superheater and thereby reducing the area of the superheater, resulting in lowing the high pressure superheated steam THP by locating the dryout zone into the superheater, the inlet gas temperature into the reheater also decreases causing the reheater discharge temperature to decrease from hot discharge header 3. Thereby replacing attemperators to cool the steam and protect the superheater and reheater tubes from damaging high temperatures or component thermal stresses.
The starting methods for the intermediate, low pressure steam generators and the low pressure turbine section are not described herein to better illustrate this disclosure's method, since they can be started with conventional methods or use the method described herein. Further, the use of an auxiliary boiler for: warm up, seal steam, deaeration steam, fuel heating, low pressure LP steam turbine cooling and other functions are not described since these elements use conventional methods.
A cold starting method after a long shutdown periods such as a weekend or maintenance is described. The HRSG is protected with nitrogen blanketing to prevent air ingress as steam pressure falls to near ambient air pressure. All steam spaces not filled with boilerwater over long shutdowns are blanketed with at least 5 psig nitrogen gas by a nitrogen line connection 27 to the horizontal drain manifold 8 (see
A hot starting method is described and is necessary for CC support of variable power sources such as solar and wind where weather can cause loss of power to the grid in minutes. If the CC is placed on dispatch service to support variable power, the hot starting method is the same as the warm starting method described above, except the high pressure superheater header 14 temperature is lowered to reduce cumulative loss of thermal stress fatigue life in starting. At the time of gas turbine shutdown, the superheater headers 14 may be hundreds of degrees above the saturated steam temperature of the boilerwater in the evaporator depending on the cool down time prior to shutdown. To minimize stresses in this condition, saturated steam flow through the header is initiated immediately after gas turbine spin-down to reduce header 14 temperature. Shutdown spin-down cooling will have caused the superheater tubes to be cooled to below saturated steam temperature and condensate forms in the bottom of each U-tubes. At shutdown, the final rows 2 of tubes may contain greater than 5% of the tube volume as saturated condensate at the bottom U-bends. The start-up apparatus 1 has a small bypass flow control valve 33 (
While the apparatus and method have been described in connection with a certain embodiment related to the most serious problems now afflicting fast starting HRSGs and is considered the most practical and preferred embodiment, it is to be understood that the invention is not limited to the disclosed embodiment. On the contrary, it is intended to cover various modifications such as: temperature levels, pressure levels, wherein components of each system and methods may be independently utilized. The described embodiment is also intended to cover various other combined cycle systems such as: supercritical steam HRSGs such as described in U.S. Pat. No. 7,874,162 SUPERCRITICAL STEAM COMBINED CYCLE AND METHODS and other HRSGs with fewer steam pressure levels, horizontal tube HRSGs with once-through circuits, intermediate and low pressure sections of once-through HRSGs, supplementary fired HRSGs and equivalent arrangements included within the spirit and scope of the invention by one of ordinary skill in the art to the appended claims.
