Patent Application
20190072006
The invention describes methods and apparatus for rapidly starting combined cycle heat recovery steam generators (HRSGs) and steam turbines while minimizing damaging effects of the thermal stress. Reducing component differential temperatures will decrease or eliminate most of the cyclical-life reducing problems recorded in conventional HRSGs and steam turbines. Thousands of Combined Cycle (CC) power plants have been installed and are operating throughout the world. In the first forty years, most were installed as base load and designed to be started and slowly warmed up a few dozen times per year. Operating experience with these CCs proved that start-stop cycles led to the greatest damage requiring major repairs, replacement and reduced availability for many plants in only a few hundred start cycles. Problems recorded for HRSGs include: superheater and reheater header cracking, weld failures, tube buckling, and drum cracks. This long recorded history has caused reduced availability and expensive repair costs. Steam turbine components are also at risk, requiring special methods to minimize thermal stress and maintain adequate clearances in starting, warm-up and loading. High differential temperatures between rotor components and thick case, or across thick walls, cause cracks and rub damage. The new specifications for CCs require loading the gas turbine to full power as fast as possible without a normal part load low temperature hold for operational, economic and emissions requirements. Many CC plants are now required to be able to start within 30 minutes after overnight shutdown and some even hourly to accommodate solar and wind power variability. This requirement can be damaging to thick wall HRSG components and steam turbines have greatly increased the challenge to solve the drum and header problems For the fast start requirements, after ignition, the exhaust gas rapidly increases in temperature to about 1,100° F. in a few minutes as the gas turbine is rapidly accelerated and fully loaded as fast as possible without a hold. A major cause of high differential temperatures in conventional HRSGs is that superheaters and reheaters are dry during a start. Because the thick wall drum in the evaporator must slowly limit pressure increase rate to manage drum wall stress, separate the swell water and establish stable dry saturated cooling steam flow does not start in the superheater or reheater for many minutes. In conventional HRSGs, the superheater and reheater tubes containing stagnant saturated steam rapidly approach gas temperature as their headers remain hundreds of degrees cooler without steam flow. As a consequence, differential temperatures cause high header and tube stresses and tube buckling loads as steam flow and tube-to-tube cooling may not be uniform. Fast starts greatly magnify these well recorded thermal stress problems. When starting the gas turbine and rapidly accelerating to full power the steam produced is too hot to start the steam turbine. As a consequence steam flow must bypass the steam turbine. Without a hold in gas turbine loading ramp the steam produced approaches gas temperature. Interstage and terminal attemperators are necessary for the high pressure superheater and reheater to produce the low temperature steam required to start the steam turbine and protect headers and tubes. Because steam flow is delayed for many minutes the tubes go to about gas temperature limiting the effectiveness of attemperators until high velocity steam is generated to atomize and evaporate the injected cold water. For advanced CCs typically four attemperators using copious cold water flow rates are required to limit over-temperature damage of the superheater or reheater and to supply turbine start steam at a lower allowable steam temperature. U.S. Pat. No. 7,621,133 METHODS AND APPARATUS FOR STARTING UP COMBINED CYCLE POWER SYSTEMS describes the use of two interstage attemperators to protect superheater and reheater components from over-temperature and reduce differential thermal stress. Two terminal attemperators one for the superheater and a second for the reheater are also described to control steam temperature for admission to the steam turbine when it is started. Attemperator over-spray of cold feedwater water, and or poor water atomization, has also been identified as another major cause of damaging thermal stress quenching of piping, tubes and headers. Moreover, the attemperator's hot metal components are exposed to quench cracking and malfunctions in normal operation. Higher steam temperature and pressure specified to improve efficiency of CCs further increases start problems. Nevertheless most HRSG designs still retain the 19th century natural circulation evaporators that require a thick wall and its related problems. The temperature differentials across the thick wall of drums in fast starts typically result in unacceptable cyclical fatigue life reduction for conventional steam drum designs.
Basic changes and innovative systems and methods are now being introduced to obtain design solutions for these proven industry start problems. The current changes concentrate on solving both the thick-wall-drum and header stress problem 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. Application of more complex evaporator flow is also being installed to reduce the drum wall thickness or eliminate the drum entirely. Reduced diameter and reduced wall thickness drums described in recently patented systems use a two-stage method of steam separation. Eight vertical secondary steam separator bottles welded to the top of a high pressure drum made of higher strength steel are operating in newly commissioned HRSGs. The additional external separators are designed to eliminate swell and liquid spray or chemical carry-over from the confined spaces of reduced diameter drums. The high temperature superheater and reheater headers are designed for only one row of tubes and made of higher strength steel to reduced diameter and thickness. Another approach is to eliminate the high pressure drum entirely by using a patented once-through Benson forced flow evaporator recirculating system using high purity feedwater. The Benson 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. Steam from the final Benson evaporator passes through a steam separator mounted externally of the HRSG casing. This separator ensures dry steam is conducted into the superheater sections of the HRSG. The dry separator is normally employed during starts to separate swell water and spray from the steam. During normal operation of this type HRSG, the separator is dry and 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 and expense. A limitation to these modifications is that both have a fixed surface area for superheating. This limits the HRSG operating range for starting, part load and the ambient air temperature performance optimization. Additionally, the fixed area superheater requires attemperators at part load reducing efficiency with some gas turbines. 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 modules. Thermal harps are fabricated in a factory into transportable modules and assembled as an HRSG on site totaling thousands of 50-to-80 foot long tubes each 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 only constructed with one row of tubes connecting critical hot headers. 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 imperfect draining of bottom headers. The fast start designed harps use three large drains per high temperature header to account for header thermal bow distortion. These drains are controlled automatically with large capacity drain pots or equivalent. On conventional units, two to three rows are often welded onto a single header and top headers may be spring mounted. With bundles redesigned for fast start, only one row of tubes per header is used per harp to minimize damage. Wherein the lower headers are free to expand downward accommodating the average expansion of a single row of tubes. Although this does not eliminate tube-to-tube differential expansion or tube-to-header differential temperature stress the single row header reduces much of the calculated stresses.
The design fixes described above are incremental improvements to resolve specific drum, header and tube stress problems caused by conventional starting methods. However the design fixes don't solve the basic problems: high differential wall temperatures of drums, headers-to-tube differential thermal stress and the means to control the steam turbine start temperatures without attemperators. A part of the solution to reduce thermal stress in starts is the once-through HRSG without drums using a wet-start method to minimize thermal stress. An exemplary HRSG of the once-through type is described in US Pat. No. 8,820,078 HEAT RECOVERY STEAM GENERATOR AND METHOD FOR FAST STARTING COMBINED CYCLES, the disclosure of which is incorporated herein by this reference. The US Patented wet start method in is not in operation at present. The start apparatus and start method start up the steam turbine without attemperators described herein this disclosure is expected to enhance the above patents utility and application. However more than 200 once-through HRSGs are currently installed. 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 200 plus once-through HRSGs in operation. These also have a unique start method, they start dry, with feedwater introduced early after flame detection in the gas turbine. These operating HRSGs substantiate the patented once-through flow path. They are typically less than 70 MW output and are constructed using horizontal tubes that are self-draining. Large utility HRSGs (the main application disclosure herein) require approximately ten times larger heat transfer area compared to the 70 MW once-through HRSGs. Structural height criteria, gas flow path and costs to mechanically support thousands of tons of horizontal heat transfer tubes justify top supported vertical tube once-through HRSG designs 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 without problematic bottom headers and the numerous drain valves and lines in conventional HRSGs. Conventional gravity draining dozens of bottom headers each with three drains, plus drums may result in reliability problems to completely drain and dry. The simple two drain valve, air blowdown system ensures fast and complete draining and drying. A two valve nitrogen blanketing system is also described in U.S. Pat. No. 8,820,078 for long weekend shut downs using automatic nitrogen blanketing system for corrosion protection.
The once-through HRSG flow path is fabricated entirely of tubes arranged in separate identical serpentine circuits. U-tubes connect long vertical finned tubes at the top and bottom in a serpentine path without intermediate headers completing an all tubular flow path between the inlet and outlet headers forming a 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, flow goes through a tubular evaporator, discharging from it directly to the tubular superheater and its outlet header. By assembling 20 or 30 circuits in parallel, a module is assembled to facilitate transportation. One or more modules complete a once-through HRSG for CCs when supported and connected in the casing. Located approximately in the middle of each circuit is where evaporation takes place in normal operation. It is simply a continuation of the individual circuits (without a drum, or separator). Depending on operating conditions the evaporation system can be located anyplace to the circuit to optimize performance (for example: maximum performance at low power or extreme ambient air conditions). From the evaporator section steam flows directly into the superheater section of each circuit. Most of the hundreds of HRSGs of the once-through type in operation start dry and evaporation initiates in the first row of the economizer during starts. A once-through steam generator can also start completely full of boilerwater through the superheater. In normal operating mode, the once-through HRSG utilizes a predictive control method to set the feedwater flow rate. In this control method described in U.S. Pat. No. 5,237,816 STEAM GENERATOR CONTROL SYSTEM, the thermal energy entering the HRSG is calculated from the gas turbine's actual measured parameters and known turbine characteristics. The input energy predicts and sets the feedwater flow (and thereby the steam flow) to match the CCs known parameters to produce maximum steam power output at low part load and full power. The water flow rate is set immediately and 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 small corrects to the actual water flow rate to account for turbine degradation, heat exchanger fouling, leakage and other factors affecting the computer calculated predictive steam flow rate. This patented method of control has been proven to have high response in 200 operating HRSGs and is well matched to small 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 the installed HRSGs are made of a high nickel (30%) and chromium (20%) alloy Incoloy 800. This expensive alloy is competitive in small HRSGs for many reasons including: dry operation, dry starting, self-draining, corrosion protection and simple water treatment. In small HRSGs material costs are relatively a lower fraction of the total installed cost. Large utility HRSGs have approximately ten times the tubing of the small once-through type HRSGs. For utility CCs as disclosed herein, the expensive alloy is cost prohibitive. Operating experience with Benson type once-through HRSGs substantiate the use of “standard carbon steel finned tubes” with full flow condensate polishing and all volatile water treatment for large HRSGs.
The mechanical design problem of supporting hundreds of tons of horizontal finned tubes (as they expand and slide across 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 hanger rods and vertical tubes in tension, is a well matched configuration for large HRSGs. One arrangement is described in U.S. Pat. No. 6,019,070 CIRCUIT ASSEMBLY FOR ONCE-THROUGH STEAM GENERATORS. It describes one of many possible mechanical configurations 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 jumper tubes to form individual circuits. Typically, each U-bend weld is made with a computer controlled portable orbital welding machine for quality control. The tubular circuits in parallel are welded to an inlet economizer header and superheater outlet header to form an individual circuit. When a number of circuits are stacked together with twenty to thirty circuits they form a module. In large HRSGs two or more modules of twenty to thirty circuits each would be typical since the modules are constrained by transportation and erection factors. A single module for a large utility once-through steam generator could be operated from the exhaust of a single LM 6000 turbine and would consist of only six or seven circuits using long utility tubes.
Full-flow condensate polished deionized feedwater is required, and is pumped into the economizer, flowing counter to the exhaust gas through approximately 60 to 100 identical parallel circuits. The same water treatment used for Benson HRSGs or supercritical steam plants is acceptable for the feedwater used in conventional carbon steel tube specifications. Water treatment is conventional full-flow deionized and polished, all volatile pH control with deaeration. The latest developments in RO, membrane oxygen control and membrane carbon dioxide control also appear well matched to the frequent start CCs. These new water treatment developments may help eliminate the need for an auxiliary boiler for starts, used in part for low pressure deaeration steam and turbine seal steam and may reduce upsets with oxygen and CO2 limits in frequent starts.
U.S. Pat. No. 8,820,078 HEAT RECOVERY STEAM GENERATOR AND METHOD FOR FAST STARTING COMBINED CYCLES includes a HRSG of the once-through type started with a wet superheater. However, the start apparatus for level control of boilerwater in the superheater is not described nor is a detailed method to start the steam turbine described. Disclosure herein, a unique start apparatus and method is described to control the water level position in the top of the high pressure superheater during a start and control swell water, pressure and temperature in the initial gas turbine acceleration and loading to full power. Further, a detailed method is described herein to start the high pressure and intermediate sections of the steam turbine. This disclosure is anticipated to assist in the acceptance of the above patent for CCs.
The invention adds a starting apparatus to a once-through HRSG, including a horizontal drain manifold and circuit drain system to allow a method to start the CC power plant in the shortest time while minimizing thermal stresses afflicting conventional CCs. The method starts large vertical tube once-through HRSGs with all the high pressure circuits (including the superheater) filled completely with boilerwater. The apparatus and start method controls the filling of the high pressure superheater with saturated boilerwater to a specific level important to the start up method. When started, the superheater functions as an evaporator generating low temperature steam as the gas turbine accelerates. In this phase the superheater is a protective evaporator heat screen that reduces the gas temperature entering the reheater immediately downstream. Concurrently, the dry stream generated is bypassed around the steam turbine and through the reheater to cool its tubes and heat its headers. By this means, the superheater and reheater components are protected from over temperature and high differential temperature thermal stress. The method also generates dry low controlled temperature steam suitable to start the steam turbine as the gas turbine is loaded to full power as fast as possible. Steam pressure, swell water and temperature are controlled by the start apparatus that functions by controlling the dryout zone location in the superheater tubes. This produces steam flow at a temperature allowable to start warming and loading the steam turbine to full flow, starting many minutes earlier than conventional HRSGs. The main goals of the start apparatus and method are:
The start-up method for the low pressure turbine section is not described herein to better illustrate this particular disclosure's method, since the low pressure section is started with conventional methods. Further, the use of an auxiliary boiler for seal steam, deaeration steam, fuel heating, steam turbine cooling and other functions since these also use conventional methods.
To achieve the goals, a once-through flow HRSG is used, since it eliminates the drum and all lower headers and most upper headers. It has an ideal flow arrangement to uniformly fill and control the water level in the superheater. The disclosed start method adds three systems; a start apparatus system, a circuit drain system and an intermediate turbine start flow path and start valve. The main component of the apparatus is a horizontal drain manifold positioned above the superheater headers. In the most frequently expected start (a start after an overnight shutdown aka “warm start”), the high pressure circuits contain saturated steam and boilerwater at several hundred psig after cooling. Prior to a start, the feedwater pump fills the HRSG. Feedwater is pumped into the economizer, displacing saturated water from the evaporator section, which in turn displaces saturated steam in the superheater with saturated boilerwater. Pumping continues, conducting water into the start apparatus from the headers. The once-through circuit flow path facilitates equal flow into each header and fills the apparatus until the level above the headers is reached. A single “level switch” is set up to measure when water reaches the full level and shuts the feedwater control valve. From this level, gravity drain and backflow ensures filling and venting of all tubes in the last row of the superheater. The single level sensor is the only device to control the start process other than the normal pressure and temperature instrumentation, thereby improving reliability. In the next step of the method, prior to ignition, the horizontal drain manifold of the apparatus is completely drained by opening its remote controlled pot drain valves. This positions the water in each superheater header discharge nozzle to be the same height above each header. With this method, a single level sensor with a broad tolerance range installed exterior of the casing can ensure all headers and tubes are filled with water at an optimum ready to start level.
At gas turbine flame detection, water in each header is drained at a computer calculated predictive flow rate by opening the circuit drain valve for a specific time. Since the volume of water in each header and tubing is known and identical, and the forcing pressure (saturated steam) is measured by the control, the calculated volume is drained to position the water level of about two-to-five feet below the headers in each superheater tube and the circuit drain valve is shut. It places the water level in the tubes to ensure the majority of swell water will expand down into the many superheater tubes typical of large HRSGs. With the last row filled about 95% with saturated boilerwater, steam flow is initiated by opening the pressure control valve in the start apparatus to the condenser. As the gas turbine is accelerated to full speed, the circuit drain system is opened, allowing swell water to fill the space vacated at the top of the tubes. Swell water and spray are separated and drained in the apparatus and pressure is controlled by the pressure control valve as steam flows into the apparatus. Temperature is controlled by the circuit drain valve that basically is controlling the length of the superheater. When dry steam flow is sensed, the steam turbine bypass system valves open, conducting all the steam generated through the reheater to the condenser. When steam from the intermediate steam generator steam is dry it is conducted through the reheater into the bypass system around the steam turbine.
The start apparatus pressure control valve is shut, transferring the pressure control to the steam turbine bypass valves. Initially, as the exhaust gas flow increases, steam pressure and temperature increase, heating the headers and cooling the tubes in the superheater and reheater. Differential temperatures are thereby minimized. The evaporation of water in the superheater significantly lowers the gas temperature entering the reheater immediately downstream, protecting it from over-temperature and thermal stress. Next the steam temperature is increased by reducing the flow of feedwater into the circuits to obtain an allowable temperature to start the steam turbine. This allowable temperature is kept constant at this low temperature until all of steam flow available is admitted to the steam turbine at flow rates compatible with turbine stress and clearance limits. Flow is split between the high pressure turbine and intermediate turbine sections. Depending upon the thickness of the turbine shells and other factors the split can be divided to the most beneficial advantage to shorten the turbine start time. In this example, steam is conducted by modulating the high pressure turbine admission valve until flow is at about 65% of full flow. Since mass flow at the reduced allowable temperature is about 130%, a special intermediate turbine start admission valve synchronized with the high pressure section admission valve modulates flow to the intermediate turbine to about 65%. The flows are synchronized to into each turbine section to keep an acceptable rotor thrust balance as flows are raised together to about 65% at the allowable start temperature. None of the flow is admitted to the intermediate turbine from the intermediate steam generator from its normal admission valve in the intermediate pressure manifold since the reheater discharge temperature at this phase is typically lower than allowable. The high pressure steam turbine exhaust is directed to the cold reheater line and then from the hot reheater discharge to the condenser through the bypass system controlling the intermediate steam pressure. In the example, 65% and 65% flow split the high pressure superheater temperature is increased by reducing the feedwater flow into the circuits causing the dryout zone to move farther towards its normal place in the evaporator. This modulation causes the hot discharge temperature from the reheater to increase to the allowable temperature to permit admission to the intermediate turbine section. When the reheater discharge reaches the allowable admission temperature, the normal admission valve to the intermediate turbine section is ramped opened to modulate flow and the special intermediate start admission valve is synchronized closed. This action allows the steam previously going through the intermediate turbine start valve to become available for the high pressure admission valve. While maintaining the somewhat higher admission temperature constant for the high pressure turbine section, the steam flow is admitted to the high pressure and intermediate turbine sections each at a constant allowable admission temperature until it both turbine sections are at full flow. The bypass system to the condenser modulates flow to control high pressure and intermediate pressure with alternate flow paths for the steam. When both turbine sections are at full flow, the steam turbine is loaded to full power by increasing the high pressure superheater discharge temperature to full power temperature at a rate compatible with allowable steam turbine stress and differential expansion to achieve normal steam turbine output.
While the methods and apparatus are 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 industrial cogeneration and smaller horizontal tube HRSGs. And, in addition, are applicable to both single- and multi-shaft combined cycle systems. The description herein is therefore set forth only by way of illustration, rather than limitation.
The HRSG is configured using a once-through type steam generator modified by adding a start apparatus including a start apparatus and a circuit drain system. This configuration eliminates the drum and most thick headers, a major source of thermal stress in starting and shutting down HRSGs. The HRSG is a vertical carbon steel tube once-through steam generator flow configuration without a steam drum. By means of a wet start method a start time to full-steam-flow shorter than conventional HRSGs is achieved without damaging differential temperatures. The steam turbine is also loaded to full power in a shorter time than conventional. An embodiment of the present invention,
The embodiment,
In this embodiment
The high pressure steam generator 25 is a once-through type heat transfer circuit constructed of long vertical finned tubes. Each circuit is independently supported from the top with a high degree of flexibility to expand downward. The tubes also have significant space to expand upwards in some rows of each circuit with rows connected by top and bottom U-bends or jumper tubes. The result is a continuous, all tubular, independent circuit of water to steam that flows directly from the high pressure water economizer inlet header 5 through a flow restrictor then though the economizer and into the evaporator section 26. The evaporator section position 26 adjusts to the optimum location in the circuit primarily depending on the gas turbine load (the turbine's mass flow, exhaust gas temperature and other factors). The location is a result of the controls that calculate of the optimum steam flow for conditions and load requirements that sets adjusts the feedwater flow control valve 16 to a predicted feedwater rate. The feedwater flow rate is the main HRSG control parameter is set immediately. The actual slow feedback response of the steam temperature corrects for secondary degradations in turbine, heat transfer, or other factors that produce errors in the predictive water flow rate. To lower superheated steam temperature from header 14 feedwater is increased into header 5 resulting in a proportional steam flow increase. From the evaporator 26 dry steam flows through the superheater and is discharged into high pressure header 14 and to the main high pressure manifold 10. This is the only high temperature header in the high pressure steam circuit and is specifically protected from thermal stress by the arrangement and methods described herein in start up and transient operation. The controls also protect against sudden large steam temperature reductions that could result in quenching thermal stress. Transients such as gas turbine trips from high power or unintended opening of a bypass valve may cause sever thermal stress. By opening a high flow capacity circuit drain valve 16 the dryout zone immediately increases the length of the superheater as the dryout zone retreats toward the economizer outlet header 5 (similar to a high capacity bottom blow in suddenly flooded drum boilers). This moves the dryout zone rapidly away from header 14 reducing its differential temperature stress and preventing possible quench damage.
In normal full power CC operation steam produced in the HRSG high pressure steam circuits flows from the high pressure superheater header 14 through the header discharge nozzle 9 to the main high pressure steam manifold 10 mounted on top of the HRSG, external of the casing, from which steam is conducted by valves and lines to the high pressure steam turbine mounted at ground level. In normal operation the high pressure steam flows through high pressure admission valve 48 and is expanded in the high pressure turbine and discharged through a one-way valve to the reheater cold header and is discharged from the reheater hot header 3. IPSG discharge valve 45 additionally discharges intermediate pressure superheated steam into the cold header of reheater 3 After passing through the reheater, steam is conducted into the intermediate pressure manifold 7 and conducted to the intermediate steam turbine IP admission valve 47. From expanding in the IP turbine, the steam is mixed with steam from the LPSG to the low pressure turbine LP. The low pressure turbine steam exhausts into the condenser, completing the steam-to-water Rankine Cycle as condensate in the hotwell of the condenser. The low pressure system is not described in detail to better illustrate the high pressure and intermediate pressure systems that are the main systems of this wet start method. Bypass systems are provided around each turbine section and are discussed in detail in the next selection.
This section describes the stress start apparatus 1 is a horizontal arrangement that provides surge expansion volume adjoining each superheater header. The apparatus 1 is fabricated of relatively small diameter pipes that provide a means to: fill and control the water level in the superheater, manage start surge, drain swell water and control pressure in the initial start. An overnight shutdown results in a warm start from several hundred degrees F. and a few hundred psig saturated steam pressure. The start sequence is dependent on filling the HRSG with saturated boilerwater using start apparatus system 1. The apparatus system 1 is illustrated in
A warm start method is described in detail and is expected to be the most common in future CC power plants. Cold and hot starts are similar, with minor differences described later. To minimize start times and cycling damage, the HRSGs are bottled up to maintain to maintain as high a temperature as possible. In a warm start, typically after an overnight shutdown, the superheater 2 contains stagnant saturated steam resulting from spin-down cooling and hours of HRSG heat loss. The saturated boilerwater is primarily located in the evaporator circuits 26 and is below normal operating pressure but still several hundred degrees above ambient conditions. Saturated steam from the evaporator section 26 tubes directly replaces any condensing steam in superheater 2. The unique method used to start requires the superheater 2 be completely filled with saturated boilerwater to minimize differential temperatures. Prior to starting, the CC condensate water from feedwater treatment system 30 is pumped into each circuit by feedwater pump 4. To fill the superheater, feedwater is pumped into the HRSG of the once-through type from the economizer inlet header 5 and displaces the saturated water in the evaporator 26, forcing it into the superheater. The flow is controlled by feedwater control valve 15, conducted through high pressure once-through circuits from the economizer header 5 through the evaporator 26 and then sequentially flows through the superheater header 14 and into the start apparatus 1. The feed water flow rate controlled by valve 15 enters from the economizer header 5 distributing it uniformly into each circuit by the inlet flow restrictors installed in each of many parallel flow serpentine circuits. The boilerwater flows in each identical circuit, filling the superheater tubes 2 and header 14. In the header, it mixes with the saturated water from the other circuits and flows vertically through the header discharge nozzle 9 to the horizontal drain pipe 11, discharging into the drain manifold 8. (Steam flow in normal CC operation would flow vertically up in header discharge nozzles 9 into the main high pressure steam manifold 10 that is now bottled up due to the turbine admission and bypass valves being closed. Water flow continues into the system until level element (LE) 21 signals the feedwater control valve 15 to stop the water flow in the upward vertical loop section of piping when the drain manifold 8 is full (
At the combustor flame detection signal from the gas turbine the circuit drain valve 16 is opened to drain a specific volume of boilerwater from its position above the header in nozzle 9. The hydraulically locked water is pressure drained by saturated steam in the apparatus from each circuits first in let row of the economizer to a flash tank 17. From 17 it is conducted to the condenser (or a feedwater storage tank equipped with nitrogen sparging). The rate of circuit drain flow volume depends upon the of the measured steam pressure and the flow characteristics of circuit drain valve 16 to remove a calculated volume to position the boilerwater level in each tube 2 to 5 feet below the header at the top of the final superheater tubes 2. This action thereby creates additional surge volume in each tube of row 2. In seconds after flame detection, the first row of water filled high pressure superheater 2 tubes are exposed to high temperature exhaust gases, the drain valve 16 is opened and water level near the top of the last row of superheater tubes 2 is lowered farther down into the tubes at a controlled rate by drain valve 16 providing space for swell water expansion. As the turbine accelerates the water in the final superheater 2 tubes rapidly heats and starts to boil and its volume swells, mostly flowing down into the additional space being created. Start apparatus pressure control valve 12 opens controlling the rising steam pressure flow to desuperheater 51. The rapidly Increasing steam pressure concurrently shrinks the steam bubbles in the swell water thereby reducing swell volume proportional to pressure and forcing the dryout level farther down into the last row 2, thereby reducing carryover. Some swell water carryover, droplets and mist not retained in the expanding steam space at the top of the last row of superheater tubes 2 are carried over to nozzle 9 and horizontal drain pipe 11 and into drain manifold 8. When its drain pots sense water (LE) 23 the drain pot valves 22 open automatically, draining water from manifold 8. The majority of wet steam will flow over the pipe loop water barrier and flow through the high capacity apparatus pressure control valve 12. Valve 12 will modulate to control the steam pressure ramp rise-rate and discharge through desuperheater 51 to the condenser. Concurrently, the circuit drain valve 16 flow continues reducing the level of water in the last row of superheater tubes 2 causing the dryout level to move down and away from headers 14. The header 14 and top of the tubes 2 start at the same saturation temperature, but steam flow generated cools the tubes and heats the headers and minimizes differential temperatures. Circuit drain valve 16 has control of steam temperature rise rate by adjusting the dryout zone location farther from headers 14, thereby increasing the effective area of the tubes superheating the steam. Adequate expansion volume is quickly generated in superheater 2 thereby reducing and eliminating carryover water into the manifold 8. The dryout zone continues to move farther away from the final superheater header 14 through the following rows of superheater and reheater tubes. These rows are located upstream of the hot reheater 3 and cool gas temperature at the reheater to prevent overheating of its tubing. Water flow drains through a one-way valve in each circuit to ensure circuit-to-circuit boiling stability during start transients. With this method and configuration, the system 1 starts steam flow at a relatively low saturated steam temperature that is initially driven by the saturation pressure and then rapidly increases as superheater area is added in a controlled method by drain valve 16. By means of the circuit drain valve 16, the dryout zone location in the final superheater tubes is adjusted farther from the header 14 to control steam outlet temperature during the start sequence. Pressure is controlled by apparatus discharge valve 12 as steam temperature starts at saturation and ramps up the header and tube temperatures concurrently to minimizing damaging differential temperatures. The need for interstage attemperators to limit tube temperature is eliminated by adjusting the position of the dryout zone. The position of the dryout zone is controlled by a computed predictive algorithm drain flow rate that constantly transports the dryout zone to an optimum position during gas turbine acceleration and loading. The calculations incorporate key turbine and steam generator characteristics plus real time measurements of turbine and steam parameters. Adjustments to the algorithm output results are made by incorporating superheater outlet temperature and pressure feedback to limit pressure. As the gas turbine accelerates and is loaded as fast as possible, the exhaust gases rapidly rise to approximately 1100° F. (depending on the turbine type). The superheater 2 filled with boilerwater and evaporating water reduces the gas temperature hundreds of degrees at the reheater located immediately downstream, protecting its tubes from over temperature. When dry superheated steam flow is sensed during gas turbine acceleration, start apparatus pressure control valve 12 is ramped closed as steam turbine bypass valves 46 and 35 are opened and modulated to discharge the steam generated through reheater 3 to control pressure. Steam from the intermediate pressure steam generator IPSG, when dry is also conducted through the reheater 3 by its discharge valve 45. The steam discharge from the hot reheater outlet header 3 is conducted to intermediate pressure manifold 7 and on through bypass valve 35 to a desuperheater 31 to condition the steam for the condenser. The turbine admission valves 47, 48 and 49 are kept in closed position and all steam generated is bypassed to the condenser. The relatively low temperature steam from the high pressure superheat headers 14 flows through the reheater 3 and cools its tubes while warming its headers. This prevents reheater 3 tubes from overheating and causing damaging differential thermal stress between tubes and headers. At rated speed, the gas turbine is loaded to full power as fast as possible. By modulating the feedwater control valve 15 the dryout zone is shifted away from the outlet header 14 and a higher temperature high pressure steam is generated by modulating the feed water valve and drain valve 16 to produce an allowable temperature to start the steam turbine.
(A low pressure steam generator LPSG system also employs a bypass system to conduct low pressure steam around the LP turbine, controlling steam flow during start up using conventional methods and not detailed to illuminate the unique start method herein.)
The bypass valves 46 and 35 will control the high pressure and intermediate pressure through desuperheater 31 as an allowable temperature to start the steam turbine reached. Flow through bypass system is modulated so as to control the steam pressure and provide an alternate path for steam while turbine admission valves are modulated during turbine loading. Steam temperature is kept constant at a low allowable admission temperature for starting the IP and HP section of the turbine. This temperature is (for example at approximately 700° F.) or if the turbine instrumentation shows the turbine bowl metal temperature is higher a constant temperature slightly above the bowl measured temperature (see U.S. Pat. No. 7,621,133). This temperature set point is maintained by regulating water flow into the HRSG by adjusting the feedwater control valve 15 that controls temperature by the position of the dryout zone. Steam flow is generated rapidly as the gas turbine is loaded as fast as possible to full power. The steam turbine is started by modulating the steam turbine high pressure admission valve 48 and intermediate pressure turbine start admission valve 49 while controlling the high pressure steam to a constant allowable temperature (for example at approximately 700° F.). Since the intermediate pressure start valve 49 all so operates from the high pressure steam line it will also be at 700° F. Actual steam flow at the low 700° F. temperature is greater than 130% of rated flow at the rated temperature, typically 1050° F. to 1100° F. The low allowable start temperature limits thermal stress, differential expansion and thrust load in both turbine sections. The flow to the turbine sections is modulated and increased at a rate compatible with turbine stress and clearance criteria. The HP turbine section flow is increased by modulating admission valve 48 and the bypass valves to about 65% of rated flow and intermediate turbine admission start valve 49 modulating flow to 65% into the IP turbine section while maintaining about 700° F. The differential pressure drop expanding across each turbine section is concurrently balanced to maintain an acceptable force on the thrust bearing. At the condition with about 65% flow in both turbines the temperature of steam in the intermediate pressure manifold 7 is too low to admit flow through the normal admission valve 47. To raise the intermediate steam temperature, the HP temperature is increased to about 800° F. (for example) to raise the reheater 3 discharge temperature into manifold 7. (The 800° F. example temperature used is a function of the heat exchange row arrangements.) Decreasing the flow into the high pressure circuits by feedwater control valve 15 moves the dryout zone in the superheater towards its normal position in the evaporator. The dryout zone transfers row-by-row toward its normal position in the evaporator section 26. Early in the transfer process the dryout zone row relocates downstream of the hot discharge of reheater row at header 3 outlet row. This accelerates the rate of gas temperature increase entering the reheater 3. Combined with increasing HP turbine exhaust steam temperature and increasing gas temperature the reheater temperature discharge also increases into the intermediate manifold 7. When the reheater 3 discharge temperature in manifold 7 rises to about 700° F., the IP turbine admission valve 47 is modulated open to provide steam flow from the reheater hot header 3 at 700° F. into the IP turbine from intermediate pressure manifold 7. Intermediate turbine start valve 49 is synchronized with valve 47 and valve 49 is modulated closed to eliminate flow from it, the start valve. The IP turbine admission steam flow temperature is kept constant at about 700° F. Steam flow to the HP turbine is kept constant at approximately 800° F. Steam flow into the IP and HP sections is now increased to 100% of the rated flow by manipulating valve 47 and 48 at rates compatible to turbine stress, clearance and thrust bearing criteria. Bypass valves are concurrently modulated to control the intermediate steam pressure. With full flow in both turbine sections the high pressure steam temperature is increased to full rated power (typically about 1050-1100° F.) by manipulating the feedwater flow rate with valve 15. The temperature rise rate is limited by the allowed stress and clearance criteria of either the high pressure or intermediate pressure turbine sections. The pressure across each section is regulated during the increase in temperature to maintain the thrust balance required. As the dryout zone is adjusted to the normal position in the high pressure evaporator 26, both turbine stages advance to full rated steam temperature and load as bypass valves 46 and 35 are modulated to the shut position. The intermediate pressure reheated superheat in steam manifold 7 automatically follows the expanded high pressure turbine exhaust to its rated temperature (depending on the gas turbine and other factors). This procedure enables full steam turbine loading while controlling stress in shell and rotor heating as well as maintaining allowable differential expansion clearances.
Cold starts are usually infrequent and may be less than 50 per year. In cold starts, the once-through through type HRSG is protected with nitrogen blanketing to prevent air ingress as steam pressure falls close to ambient air pressure after a long period of shutdown. All steam spaces not filled with boiler water over long shutdowns or maintenance periods are blanketed with at least 5 psig nitrogen gas via a single nitrogen line connection in the high pressure steam manifold 10 and apparatus system 1. The same start method is used as described above, except, as water fills the nitrogen gas space, the gas is compressed by flow from the feedwater pump 4 and is used as the motive pressure to drain and lower the level in the last row of high pressure superheater tubes 2. When sufficient steam pressure is generated during turbine acceleration, it takes over as the motive pressure to drain the circuits through drain control valve 16. The start apparatus system 1 is positioned to be closely coupled to the high pressure steam outlet header 14 and is also filled with compressed nitrogen. In the prestart sequence, feedwater control valve 15 will control feedwater flow into the circuits. Water is pumped into the economizer header 5 forcing treated boilerwater from the economizer and evaporator to fill the superheater 2 and apparatus system 1 to level LE 21 in drain manifold 8. When the HRSG is started completely empty after a long layup the nitrogen gas will be vented to keep its pressure sufficiently low to prevent excessive gas loading of the condenser's gas removal system during starts. At this condition, the start method described above for a warm start is the same, once the start apparatus is filled with water and compressed nitrogen maintained over approximately 60 psig.
Hot starts are 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 on an hourly dispatch service to support variable power, the start method for hot is the same as the warm method described above, except the high pressure superheater header 14 temperature is lowered to improve thermal fatigue life. At the time of gas turbine shut down, the superheater header 14 may be 400 to 600 degrees F. above saturated steam temperature of the water in the evaporator. If the combined cycle must start within minutes, the superheater header may be too hot to avoid thermal shock stress when it is filled with saturated water. To minimize stresses in this condition, saturated steam flow through the header is initiated immediately after gas turbine shutdown to reduce header 14 temperatures. Shutdown spin cooling will have caused the superheater tubes to be force cooled to saturated steam temperature and condense the steam in the tubes. At shutdown the final rows 2 of tubes contain greater than 10% by volume of saturated condensate at the bottom U-bend bends. The start apparatus has a small bypass flow control valve 33 (
While the apparatus and method has been described in connection with a certain embodiment related to the most serious problems now afflicting 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, but on the contrary, it is intended to cover various modifications such as: a supercritical steam HRSGs U.S. Pat. No. 7,874,162 SUPERCRITICAL STEAM COMBINED CYCLE AND METHOD, horizontal tube HRSG with once-through circuits, intermediate and low pressure sections of HRSGs, Benson flow path 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.
