Increasing the availability, efficiency and reliability of power plant capacity through its plant life extension is the most economical method for meeting the incremental energy demand.
Servicing the existing EUAS (Electricity Generation Public Company of Turkey) Utility plants are not feasible in the short run, since EUAS traditionally prefers to use their own resources or alternatively they work together with original boiler supplier(s).
After “Privatization” would be implemented in future, the new owners will certainly ask experienced service companies to make the necessary upgrading of existing utility units. This paper presents the necessary approach for assessing the boiler remaining life and its role in plant life extension.
Meeting the demand for electric energy can be achieved by improving the availability, efficiency and reliability of the existing boiler capacity through life extension. Improved plant performance can provide power for as little as 10% of the cost of new plant capacity, when measured on a cost per installed KW basis. It is also possible to reduce plant emissions while making modifications to improve plant performance.
The Condition Assessment begins by defining the operating objective for the plant;
· How many more years of service are required from this plant?
· Will the plant be base loaded or used for cycling duty?
· What capacity will be required of the plant, and at what levels of availability and reliability?
· What are the allowable limits for emissions from the plant during its expected life?
With the operating objectives of the plant defined, it is necessary to assess the current condition of the unit and determine if meeting the objectives is feasible. Non-destructive methods exist for evaluating boiler condition and for estimating remaining useful life and time-to-failure.
With current condition and remaining life estimates in hand, it must be determined if the objective is feasible for these units. In some cases, evaluation may indicate that the unit can no longer be repaired or altered, but more often it is found that with repair and alteration, the boiler can continue to operate in an efficient, reliable, environmentally acceptable manner.
Given the objectives of operation, alternative cases for improving unit performance and reducing emissions can be considered. Each case will have perceptible capital and operating costs for economical evaluation. Case-by-case requirements will dictate the necessary criteria for selecting the optimum course of action.
Project Plan
A plan should be developed for evaluating the plant and determining its viability for extended operation. It should define the critical decision points and include a clear statement of the future needs for the plant. The condition of the Power Plant can be assessed without knowing the future plant needs. However, the scope of upgrades considered, including component replacements, will be directly affected by the projected plant requirements.
Condition Assessment of Fossil Fuel-Fired Boilers
Fossil Fuel Fired Boilers operating at higher temperature and pressure are subject to aging and finite life of major components due to creep, fatigue and interactive creep- fatigue. Coal firing accelerates the normal wear and degradation of heating surfaces due to erosion and corrosion. In addition, boilers can experience degradation from sources that are not fuel related such as inadequate water chemistry controls, effects of cycling operation, or corrosion of surfaces during extended lay-up of the boiler.
The problems associated with creep and creep-fatigue are most likely on boilers that have been in operation for 20-years or more. Typically it is these plants that implement life extension programs and install upgrades to reduce emissions. Although the condition assessment program must consider the entire boiler, the emphasis is to evaluate those components with a cost of replacement, which has major economic impact on the life extension project.
Phased Approach
We would recommend three-phase approach to condition assessment. That would describe the steps followed for a typical project done in the USA. The three phases are defined around the plant inspection outage as follows,
Phase-I. Pre-Outage Planning
· Evaluate maintenance and operations history
· Determine the critical Components for the unit
· Establish outage inspection / test plan
Phase-II. Outage
· Implement inspection/test plan
· Perform root cause analysis, as required to ensure all needed data be obtained during outage. Install instrumentation to support on-line testing if required by the Phase-I plan, or for root cause analysis.
Phase-III Post Outage Testing and Engineering Analysis
· Final remaining life analysis
· Operational testing and analysis, if required
· Repair/ replace recommendations with associated cost
For a feasibility analysis, it is common to limit the project to a Phase-I assessment, which is essentially a study that considers only plant historical data, including;
· Unit operating hours
· Unit mode of operation, ie. cycling vs. base load
· Cycling characteristics- frequency, ramp rates, hot, warm or cold,
· Past failure history including failure analysis reports
· Maintenance history
· Replacement/ Upgrade history
· Materials of Construction
· Actual steam operating temperatures
· Specific characteristics of the boiler design
Key Boiler Components
For a typical electric utility power boiler, some of the components can be expected to fail, and require replacement after as little as 20 years of operation.
Component Replacement Schedule
For a typical High temperature/ High Pressure Utility Boiler
Typical Life
In Years Component Replaced Cause for Replacement
20 Miscellaneous Tubing Corrosion, erosion, overheating
Attemperator Fatigue
25 Superheater (SH) Creep
SH Outlet header Creep- Fatigue
Burners and Throats Overheating – Corrosion
30 Reheater Corrosion
35 Primary Economizer Corrosion
40 Lower Furnace Overheating- Corrosion
Note: Actual component life is highly variable depending on the specific design, operation, maintenance and fuel.
High Temperature Headers
High temperature headers, including the superheater outlet headers, operate at 900F (482C) or greater, and with stresses which make them susceptible to creep, the time dependent phenomenon of increasing material strain with constant stress. Creep interacts with thermal fatigue to accelerate the onset of damage.
Three factors influence creep- fatigue in the high temperature headers of the superheaters
· Combustion
· Steam Flow
· Boiler Load
Burner inputs can vary causing uneven heat input across the boiler. Air distribution can vary, and boiler slagging and fouling can occur, leading to unbalance flow of gases through the superheater and convection passes. The net effect is variations in heat input to the superheater and reheater, and variations in tube outlet leg temperatures entering the outlet headers.
Large differences can occur at individual tube bore locations. These outlet temperatures can occur at individual tube bore locations and these outlet temperatures are greater than the surrounding header temperature and cause localized thermal stress.
Changes in boiler load can increase these differences. Also, decreases in boiler load often result in a reversal of individual thermal stresses at the bore holes locations. When decreasing boiler load, the superheater tube outlet temperature can be less than the surrounding header. This reversal of thermal stresses results in fatigue, which when combined with creep, can initiate cracks in the header along the bore hole penetrations. Load cycling thereby increases the potential for header ligament cracking.
In addition to the effects of creep and creep- fatigue on the header, other potential damage, which should be investigated, includes external cracking due to the stresses from header expansion and piping loads. Header expansion is more likely to cause damage on cycling units where it produces fatigue cracks at header support attachments, torque plates, and other branch connection welds.
Since the superheater outlet header experiences greater temperature and thermal expansion than the furnace roof enclosure, on/off cycling can also result in tube stub-to-header weld cracking. These fatigue cracks are found on the tube side of the weld and are most likely to occur on tubes near the ends of the header. Steam piping flexibility problems can transmit excessive loads to the outlet nozzle of the header and result in externally initiated cracks at the outlet nozzle weld.
If present, longitudinal seam welds in high temperature headers are of concern because of the potential for sub-surface weld flaws, which can promote crack growth due to creep. Finally, a problem seen on some outlet headers is related to the thermal shock and is associated with cycling. In plants where more than one boiler or header are tied to a common blowdown tank, it has been found that condensate can sometimes back up through drain lines and enter a hot header during startup. The resulting thermal shock can damage the header in areas immediately adjacent to the drain connection.
Condition assessment of high temperature headers should include a combination of “Non-Destructive Examination (NDE)” techniques targeted at the welds where cracks are most likely to develop. All major welds on the header including outlet nozzle, torque plates, support lugs, support plates, and circumferential girth welds should be examined non-destructively.
The welds at miscellaneous connections and branch lines such as drains, thermal wells, radiograph plugs, and hand hole caps should also be examined. The internal header should be inspected in locations near the drain lines if the boiler arrangement allows the possible back-flow of condensate. Any seam weld should be examined by surface NDE methods such as magnetic particle or liquid dye penetrant testing, as well as a volumetric examination using electronic test methods. The heat affected header material adjacent to welds can be examined for creep damage by metallographic replication or, if necessary, by sample removal and testing.
We would recommend internal examination of at least one header tube bore hole to look for ligament cracking. If gone undetected, the first indication of severe ligament cracking may be steam leaks at the tube stub-to-header welds, at which time immediate replacement may be the only option. Borehole examinations should include removal of oxide scale that could hide damage. A special test can be done by oxide removal followed by fluorescent dye penetrant inspection for maximum sensivity. The damage most likely to require header replacement is ligament cracking. Its early detection is given the utmost priority. In most instances, other cracks are repairable.
High Temperature Tubing
The superheater and the reheater superheater may each have tubes with finite life due to the effects of metal creep. The creep life of superheater tubes is reduced by higher tube metal operating temperatures and/or higher stresses. Erosion and/or corrosion associated with coal ash attacks the outside diameter of the tube causing wall thinning and increasing tube stress. Excessive moisture or condensate in sootblowing steam can also erode tube wall material. Depending upon the arrangement of the surface, excessive stresses associated with thermal expansion and mechanical loading can occur.
Lower grade alloys, such as ASME SA-213 T11 and SA-213 T22, containing 1-1/4 Chromium and 2-1/4 Chromium respectively, operating at high temperature will experience oxidation of internal surfaces. The internal iron oxide (Fe3O4) continues to grow in thickness and has an insulating effect on the tube. This time/ temperature dependent oxide growth and resulting temperature increase in tube metal further reduces the creep life.
Condition assessment of the superheater tubes is possible because of the development of NDE methods, such as “Non-destructive Oxide Thickness Inspection System”, that allow measurement of the internal oxide layer as well as the tube wall thickness. Oxide growth correlated to historical metal temperature. Using the tube’s thermal history, along with the calculated stress due to wall loss, it is possible to predict remaining life for the tube even though no failures may yet have occurred. In addition to this inspection, condition assessment of the superheater includes visual inspection, ultrasonic thickness (UT) testing, and tube sample analysis. UT testing is performed, especially on coal-fired units, to quantify general superheater tube wall loss. Testing is targeted at the location of the hottest tubes in the outlet banks of the superheater and reheater.
Cycling- Other Condition Assessment Considerations
Cycling operation, particularly on/off cycling, has become common place in North American Utilities. The condition assessment program is necessarily directed at the major components that have the greatest economical impact and which are subject to finite life due to their operating temperature and stresses. Cycling operation can lead to component damage, which is not a consequence of creep, but it is the result of thermal shock and fatigue. Two components of concern are the economizer inlet header and the spray attemperator or desuperheater.
Severe economiser inlet header damage has been experienced on drum type utility power boilers that are daily on/off cycled. The problem is unit specific and it is most likely to occur where the economiser inlet header is located within the convection gas pass of the boiler. Boilers held in overnight stand-by without firing would experience pressure decay and a lowering of drum level. Concurrently during this idle period, the stack effect of the hot boiler and in-leakage of air cause the economiser to heat up. The economiser may reach saturation temperature since there is no flow into the unit during this period. As relatively cold water is introduced into the hot economiser header, it produces a thermal shock within the header. The magnitude of the thermal shock and the frequency impact how much damage the header experiences. This damage will occur in the header boreholes and tubes closest to the feedwater inlet. Condition assessment simply involves the removal of a tube segment or hand hole fitting to allow internal visual inspection with a fiber optics probe or video probe system.
The attemperator, normally located in the piping between the primary and secondary superheater, is also subject to damage associated with thermal fatigue and thermal shock. Steam exiting the primary superheater passing through the attemperator can be in excess of 900F (482C). When relatively cold feedwater 300F (149C) is sprayed into the steam for tempering, the components of the attemperator assembly are subjected to large thermal stresses which, over time, lead to failures. The attemperator is inspected by removing the spray head assembly and performing internal inspections with fiber optic or video probes.
Remaining Life Analysis
Once the Phase-II testing has been accomplished and data complied, the damage must be evaluated and decision should be made whether to repair, replace or reinspect. These decisions are based upon the component’s useful remaining life or end-of-life. End-of-life may be the point at which damage has accumulated to where failures occur, or when the cost of inspection and repair exceed replacement cost.
End-of-life may also be the point where the risk of failure is unacceptable due to the hazard to plant personnel. It is important that guidance be given on the acceptable remaining life when preparing the project plan.
The method of quantifying remaining life varies depending upon the component. For high temperature tubing such as the superheater and reheater tubing, creep rupture data is used to estimate a time to failure. For low temperature tubing, remaining life is determined by calculation of wall loss rate. This is used to predict when a tube will be at minimum acceptable tube wall thickness. For thick walled components such as superheater outlet headers and steam piping that operate at high temperature susceptible to creep and fatigue, remaining useful life is a function of crack initiation and creep crack growth.
The basis of calculating remaining life of superheater tubing is ASTM creep rupture data and Robinson’s Rule of life fractions. If operating conditions were constant for the tube material throughout its life then remaining life calculation would be a simple task.
Creep rupture data is published with stress as a function of Larsen- Miller Parameter (LMP) where
LMP= T x (20 + log time ) x 10 –3
T = constant temperature of material, in Celsius
time = time at temperature T, in hours
For a specific material, if the stress (an easily calculated value for tubing) is known then the LMP can be found from ASTM curves. With an estimated tube metal temperature, the LMP can be used to calculate a tube life. The difficulty of this method is the fact that tube conditions are not constant. Internal oxides which grow on the tube ID have an insulating effect and cause increased tube metal temperature over time. At the same time, tube wall loss from erosion or corrosion results in increased tube stress over time.
Calculation of tube life must allow for these changing operating conditions. Robinson’s Rule says that a tube’s life will be expended when the sum of its life fractions equals unity,
(t/tf)1 + (t/tf)2 +……+(t/tf)n =1
where t and tf are actual hours of operation and predicted total hours of life, respectively, at each set of unique stress and temperature conditions defined by subscripts 1 through n. PC programs are developed to address the changing operating conditions for tube life.
Life prediction for thick wall components is more complex and utilises time dependent fracture mechanics (TDFM). In the past, software programs were developed to allow prediction of crack growth under the influence of creep. The basic expression for crack growth as a function of crack tip driving force for creep, Ct, is:
da
---- = bC t m
dt
Where a is a crack depth, t is time, and both b and m are material constants.
Through continuing work as sponsored by EPRI, a software program was developed which was called the “Boiler Life Evaluation and Simulation System” (BLESS). The BLESS program has two unique features that are improvements over the previous programs.
The program incorporates algorithms that allow for the calculation of crack initiation in addition to crack growth and the program automatically calculates the stress in complex geometry such as header ligament locations.
Upgrade Feasibility
After determining the current condition and remaining life of key boiler components and obtaining cost estimates of any major components needing replacement, the feasibility of the operating objective should be reviewed,
· Can this unit economically meet the requirements of the objective?
· How costly will required repairs and modifications be?
In rare instances, the cost of modifications may exceed the cost of building new capacity. In these cases, the owner must determine if another objective can be met by the unit or if it should simply be retired.
More often the plant can successfully modified to meet the requirements at a fraction of the cost of a new capacity. A series of options which meet the project objective need to be developed, with an estimate for each of the associated capital costs, operating costs, and payback on investment. Selection criteria will vary from one operation to another. But generally speaking, the alternative which maximises the return on investment will be chosen course of action.
Capacity Increase and Emissions Reduction
Because of the investment of capital in a life extension program, it is common to look for capacity increases as part of the upgrades to the plant. Once it is determined that life extension and upgrade is feasible, it is necessary to evaluate the options available for increasing capacity. Since plants designed and built 20 or more years ago, were not required to meet current environmental emissions limits, any upgrades must also consider control of emissions to meet current and future regulations. In general, determination of the best method for control or reduction of emissions involves evaluation of combustion process alternatives (front end) as well as options for flue gas cleanup (back end control) and Flue Gas Desulphurisation (FGD). Options for capacity increases can be logically evaluated with the combustion options.
Capacity Increase
Increases in boiler capacity may not be feasible. However, if the output of the unit has declined due to lost efficiency and unavailability, the capacity improvement should result from equipment upgrades and refurbishment, and the improved availability. Because the maximum capacity of the boiler is a function of many parameters, increases to boiler output have to be made considering each parameter. The design parameters which affect capacity can be grouped into the categories of combustion and circulation.
Combustion parameters for fossil fuels such as coal include fuel characteristics- heating value, moisture content, grindability, ash content, ash characteristics (fouling and slagging properties) and volatile matter content. The fuel will directly affect fuel handling equipment capacity, burner capacity and fan requirements. In unit design, the combustion process is taken into account when establishing furnace volume, burner-input limits including burner spacing or heat release rate in the burner zone, and spacing of radiant and convective heating surfaces. These geometric limits for the heating surfaces are influenced most directly by the fouling and slagging properties of the coal ash.
The circulation parameters are linked to the boiler’s fluid and steam side capacity limitations. Circulation parameters include drum internal capacity, riser and supply tube flow limits, wall tube versus heat input requirements, and convection pass flow and pressure drop limits.
Emission Control
Whenever power plants are upgraded or modified, emission control options must be considered. Control Technologies must be added to bring the plant into compliance with local regulations. Air pollution control legislation has been adopted by most industrialised nations and continues to become more widespread. The focus of these regulations has been on power plants that emit pollutants as a result of the combustion process. The pollutants of particular interest are sulfur dioxide (SO2), nitrogen oxides (NOx), carbon dioxide (CO2), and particulate and air toxins. Emissions of these pollutants are regulated in any of four ways:
· Emission standards
· Percent removal requirements
· Fuel restrictions
· Technology requirements
Retrofit technologies have been developed for a broad range of emission control measures. This allows power plant operators to consider the advantages and disadvantages of more than one option for a particular emission control problem.
A fabric filter or electrostatic precipitator (ESP) is typically used for particulate control. The combustion process is modified to control NOx by replacing the old burners with low Nox burners. Sometimes it becomes necessary to supplement the control of NOx by placing additional equipment after the combustion process. Selective Catalytic reduction (SCR) and Selective Non-catalytic reduction (SNCR) systems have been used for post combustion Nox removal. For SO2 reduction, there are three basic options
· Switching fuels to a lower Sulphur coal
· Installing a fluidised bed combustor
· Installing post combustion process systems
Each has advantages and disadvantages.
Upgrades
Many boilers have been upgraded to increase capacity from original design. Evaluation requires a complete engineering analysis, which examines all of the relevant combustion and circulation parameters. Because of conservatism of some older designs, it is often possible to extend the boiler limits.
In general many combinations of component changes may be possible to address capacity increases while lowering emissions. Considerations must also be given to unique operating parameters such as cycling and its affect on key components. The design engineer working with the plant owner must economically evaluate the options and determine the best option for specific objective of the plant.
Upgrading of coal fired boilers will require the greatest capital expenditure since more systems have to be addressed including fuel handling equipment, fuel preparation equipment, and ash handling equipment. Among the systems that can be enhanced through unit upgrade are.
· Use of the latest burner technology for NOx control
· Upgraded coal pulveriser designs which provide for capacity increases and improved pulverised coal fineness
· Modernised control systems for tighter regulation of boiler operation for greater efficiency and better emission control
· Advanced boiler circuits such as spiral furnace geometry or internally ribbed tubing to enhance circulation,
· Improved monitoring and cleaning equipment,
· Addition of Flue Gas Desulphurisation.
· Upgraded materials in the superheater for high temperature headers along with enhanced header designs that address tube flexibility and cycling service needs
· Redesigned heating surfaces to address absorption and internal circulation as well as gas side velocities.
Summary and Conclusion
There are many possibilities to consider when upgrading and extending the life of older fossil fuel firing power boiler capacity. Key to success of an upgrade project is a clear understanding and statement of the long-term requirements of the plant.
The first critical step in the project is assessment of the remaining useful life of the boiler and key plant systems. Once it is confirmed that continued operation of existing plant system is feasible, and then the options for upgrading the plant to meet objectives can proceed.
The best combination of modifications for reducing emissions while increasing capacity requires evaluation of alternatives for both combustion and post combustion emission control.
In future we should also consider application of CO2 capture and sequestration capabilities, adding more capacity of electrostatic dust filters (E/P) and FGD systems to protect Mother Nature as well as to avoid global warming.
Experience has proven that in most cases extending the life of an existing plant is a viable and economical option to meet growing demand for power.
We are confident that technology and experience are available for the Turkish Entrepreneurs for better and feasible operation of the existing power plants.
Your comments are always welcome
Haluk Direskeneli- Energy Analyst
ODTU ME’1973, Ankara MMO 6606
2012 National Coal Policy for Turkey
