Steven C Stultz, Consulting Editor
Owner/operators attending the Fifth Annual Meeting of the Australasian HRSG Users Group (AHUG) held in Sydney, New South Wales, Dec 8-10, 2015, reported experiencing many of the same problems facing gas-turbine users the world over—some exacerbated by the relatively small size of the electric-generation industry in Australia/New Zealand.
In evidence this year was an underlying concern brought on by the “the export value of gas.” Many plants no longer operate as designed. As operations changed, so did the demands on equipment, systems, chemistry, and plant personnel. New risks appeared. But new lessons learned were brought here, and discussed energetically.
Below is a summary report on the event, including discussion points and selected participant questions and comments.
AHUG participants don’t hold back. They can’t. Interaction is encouraged and vigorous. Each discussion quickly becomes a dynamic blend of tested knowledge and creative ideas, and in the words of David Addison, a member of the steering committee, “The only bad question is the one you don’t ask! If you show up with a question you’ll get it answered, or you’ll be a lot further down the path of getting an answer.”
The 2015 event contained specifics on plant operations, maintenance, cycle chemistry, and storage. It featured interaction among presenters, equipment specialists, and users. Final-day workshops focused on HRSG inspection planning, life assessment, and advanced alloys. Sponsors and exhibitors included ALS Power Services, Conco Systems, Duff and Macintosh, Flexim Instruments, HMA Group, IAPWS, and PowerPlant Chemistry magazine.
This year, the principal takeaway was the taxing trend toward cycling and, eventually, short- or long-term layup. That means new demands on equipment, and new demands on operators. It means new demands on cycle chemistry and monitoring, a greater need for clear policies and procedures, and the ability to manage with reduced staffing and training.
For Australasia, the driving force is gas supply, which was discussed throughout the conference. But such operational change is also a growing global concern as power generators wrestle with changes in demand and the impacts of renewables on their systems.
Fourteen presentations set the foundation and followed a general agenda from fuel impact to operations to layup to inspection strategies. Underlying all was the need for proper cycle chemistry, a need becoming more apparent to owners and operators globally.
Operation modes dictated by gas prices
In Australia, inexpensive long-term domestic gas contracts, sheltered from the world stage, are gone. Colin Gwynne of Aurecon, a consulting and services firm operating globally, focused on this shift and its largely unexpected impact on daily and long-term plant operations.
Since 2013, the Eastern Australian gas market has moved from domestic power generation supply to export LNG. The driving force: International LNG prices to support gas-fired projects outside Australia. Domestic power demand also has decreased.
Therefore, local gas suppliers are reluctant to sign long-term domestic supply contracts with their traditional power customers. And even though LNG plants in the Middle East have reduced production by about 30% since 2013, new LNG facilities are coming on line in Eastern Australia. Most are capitalizing on an abundant Australian coal-seam gas supply.
The result: Established gas-fired plants now face an uncertain future, and need to change their modes of operation. Most base-load units are moving into a progression of cycling, two-shifting, peaking, and ultimately layup and storage. Cycle chemistry must now take a lead role in these modified operations and in any short- or long-term layup activities.
As Gwynne would stress, all of this is new for many power generators. Gone are the days of historically low and stable gas prices. Australia is pioneering large-scale coal-seam gas development, exposing its power producers more to the world stage. And planning for uncertainty is the new mode for these overlooked long-term customers.
Government forecasts show increasing LNG exports through 2020, with no domestic gas-fired power generation additions until 2025. More extreme predictions include a long-term (potential) return to coal-fired generation—the traditional Australian power bedrock. Although this seems unlikely, nothing is certain.
Thus layup and system chemistry were significant topics at this fifth meeting of the user group, which began with three case studies that follow.
1. Osborne Cogen. Commissioned for cogeneration service at the end of 1998, ATCO/Origin Energy Ltd’s Osborne Power Station, located near Adelaide, South Australia, had been in 180-MW baseload operation (120 MW of gas turbine power, 60 MW of steam) until recently (Fig 1).
Chemistry had been optimized towards the recommended IAPWS (International Association for the Properties of Water and Steam) program consistent with its operating profile. But recently Osborne has gone through a further change to more flexible operation and more startups. This has required even more chemistry changes. Current plans call for dehumidifiers and a nitrogen generator for layup and storage. A gas bypass stack also is being considered for long-term flexibility.
2. Tallawarra Power Station. Designed for cycling, EnergyAustralia’s Tallawarra station in New South Wales (260 MW gas, 160 MW steam), commissioned in January 2009, has experienced blowdown and carryover issues. The three-pressure HRSG has been operating on trisodium phosphate (TSP) treatment; feedwater is AVT(O), all-volatile treatment with a few parts-per-million (ppm) of oxygen present.
The unit has experienced low dissolved oxygen and high iron transport. Although some of these issues have been resolved, Tallawarra also is facing an uncertain future.
A new operating philosophy is being considered. Modifications include nitrogen capping of the feedwater tank for wet layup, degassed cation conductivity to improve steam-turbine startup, and water-treatment plant modifications to permit continuous reliable operation when HRSG demand is zero.
3. Darling Downs. Originally designed for baseload (3 × 120 MW gas, 270 MW steam with bypass stacks), Origin Energy’s Darling Downs Power Station in Queensland had many operating issues after commissioning in July 2010. These included LP drum feedforward stripping ammonia and oxygen from the HP drum, poor-quality recycled blowdown condensate (corrosion products), and superheater exfoliation. Air-cooled-condenser corrosion control was difficult because of high pH (about 10).
Plant operation is now two-shifting, with one or two GTs taken out of service. Layup and storage systems are under review. Considerations include nitrogen capping, dehumidified air, chemical dosing before layup, and drainage system changes. Operators predict more steam/water-cycle corrosion and know that more shutdowns will provoke more exfoliation.
The three case studies showed, to varying degrees, the impact of modified operations. Comments and discussions on correct oxygen levels followed, including specific drum-level control experiences and the need for proper testing (IAPWS). This set the stage for the presentations that followed.
Maintenance for long-term storage
Stanwell’s 375-MW Swanbank E Power Station in Queensland (Fig 2) had the largest gas turbine in Australia (Alstom GT26) when commissioned in 2002. It set a world record (unofficial) of 254.8 days of continuous operation.
But the station was removed from service in December 2014 and is not scheduled to return until 2017. In a public statement, Stanwell explained: “Analysis of the electricity and gas trading markets concluded that greater value could be achieved from Stanwell’s gas entitlements by selling the gas rather than using it to generate electricity.”
A comprehensive cold-storage and preservation program for all systems began; site labor was reduced to a caretaker team. Ongoing lessons learned, covered in detail by Stanwell’s John Blake, could be helpful to other owners and operators.
To prepare for storage, a full baseline inspection documented component and system conditions. Major storage risks predicted are outlined below.
1. Pitting and general corrosion:
- Steam/water side—HRSG, steam turbine, piping.
- Gas side—gas turbine and HRSG hot gas path.
- Under-lagging corrosion—steam, gas, and feedwater lines.
2. Corrosion fatigue:
- Steam/water side—HRSG and steam turbine.
3. Acid dew-point corrosion:
- HRSG gas side.
This storage process began with Australia’s AS3788, “Pressure Equipment: In-service Inspection” and Clause 4.6, preservation-plan requirements and return-to-service procedures.
Blake outlined specific steps taken and lessons learned for both inspecting and preparing the HRSG and its associated steam/water and gas path, gas turbine, steam turbine, and generator. Balance of plant discussions included gas yard, plant air, control systems, and pumps.
Relative-humidity monitoring details also were given, showing equipment and locations (with ongoing lessons-learned updates). Cold storage monitoring trends were then presented for all major equipment.
Blake stressed vigilance to every detail, such as valve tagging to identify those modified for air circulation. He listed areas easily overlooked, such as draining the flash box on the side of the condenser.
Perhaps most beneficial were the cold-storage lessons learned:
1. New equipment is needed (dehumidifiers, for example). This should include critical spares (Fig 3).
2. Plant staff must understand the impact of every change (for example, valve position) made during lay-up.
3. The entire process (including changes) must be clearly recorded and traceable.
4. “Don’t just set and forget.” Staff should always look for improvements. This means reviewing all ongoing strategies, not just the original plan.
5. Ongoing strategy reviews should include all site personnel.
During comments and discussions, Barry Dooley, Structural Integrity Associates Inc and chairman of the AHUG steering committee, stressed the LP turbine as a critical risk location for any lay-up beyond three days. Dooley also cited continuing IAPWS work on film-forming amines for protection, a topic that would be discussed again later in the meeting.
Sampling strategies for cycling plants
If you can’t measure a process, you can’t control it. And although good sampling systems are critical for any plant, they become more critical during flexible operation. This was the summary message from John Powalisz of Sentry Equipment Corp. His presentation focused on sampling techniques to protect assets, maintain output, predict failure, and prepare systems for startup and potential layup.
Steam and water sampling were covered first. As EPRI tells it in Report CS-5164, “Fossil Plant Cycle Chemistry Instrumentation and Control—State-of-Knowledge Assessment,” “The primary objective of any sampling system is to transport and condition a sample without altering the characteristics of interest. The system parameters which need to be controlled are velocity, pressure, and temperature.”
If the integrated steam and water sampling system fails to control flow, pressure, or temperature (secondary cooling); if it fails to give consistent online flows during startup or low load (night shift); or if it doesn’t help mitigate high iron transport during startup or load changes, impacts will be negative. In general, if flow is too high (startup), system components could be stressed and some readings might be inconsistent. If too low, data errors and air ingress are common.
Powalisz emphasized the most controllable areas: procedures, training, and technology. These become even more critical when cycling. The question: What is the best approach for each particular plant?
Attention turned to a series of manual-panel best practices requiring no capital investment. For example:
- Monitor blowdown samples containing high levels of particulates for safety issues.
- At startup, establish sample flow at minimum level to feed analyzers.
- Close valved rotameters as soon as possible after a shutdown/cycle off to hold liquid in the flow cells and to keep probes wet.
- Set VREL® valves (high-pressure sample flow-control valves) to the fully closed position during shutdown.
- Simple low-cost upgrades can also improve sampling consistency:
- Increase the size of primary sample coolers to allow more “forgiveness” (for improper settings).
- If missing, add total flow indicators so that total sample flows can be set properly.
- Use preset combination back-pressure regulator/relief valves to improve flow consistency to analyzers and eliminate lost flow through pressure-relief valves/lines.
- Add ability to valve-in flush water to keep probes wet during shutdowns.
- Add a degassed cation-conductivity panel to discern air from contamination during low-load operation.
- Add a large-surface-area high-pressure magnetic trap or similar device to capture magnetite as far upstream as possible in lines with high particulate counts.
Alternative and supplemental-action discussions followed. The presentation then concluded with these recommendations:
- To address insufficient staff, automate critical sample points.
- To improve instrument reliability for limited staff, consider outsourcing instrument maintenance.
- To address high iron transport/plugging, add a high-pressure magnetite trap or put in place automated blowdown practices—or do both.
Good sample conditioning systems should increase safety for both personnel and instruments, provide representative samples to the analyzers, be easy to set up and use, be intuitive, and have low maintenance costs.
Available standards and guidance documents were then listed for ASTM, ASME, EPRI, IAPWS and VGB.
The bottom line was this: You might not be able to control operational modes or numbers of employees, but you can control procedures, training, and choice of technology.
Significant maintenance events
Inspection of Otahuhu B’s triple-pressure HRSG revealed safety issues outside the casing; reliability issues inside. The Siemens single-shaft combined cycle, powered by a V94.3A gas turbine, had a complex history, with several consultants and engineering contractors onsite since its commissioning in 2000.
Steering Committee Member Mark Utley of Contact Energy Ltd (CEL), owner/operator of the Auckland (New Zealand) facility explained that the as-supplied HRSG was of paramount concern. CEL assumed responsibility for the boiler soon after installation to address non-compliant welds and long-term risks. Operations were acceptable until 2008; further boiler defects and lingering construction faults surfaced at that time.
The first major tube failure was in 2008, specifically creep damage where a T91 superheater tube was connected to a P22 header. CEL replaced all at-risk headers with P91 (Fig 4). That same year, the owner called for EPRI chemistry benchmarking and launched a significant steam-cycle chemistry upgrade. Gas-turbine firing temperature was increased to recover lost capacity and HRSG safety valves were resized.
Before this outage, the plant had half of Structural Integrity’s 19 recommended cycle-chemistry instruments. This was brought to 100% by 2009. Benchmarking improved from “average” to “above average.”
But for the next four operating years, disturbing HRSG events and findings continued. These included faulty welds and cracks in lugs supporting headers, among others. A long layup for repairs caused fin and tube fouling (Fig 5) and backpressure limitations on the gas turbine attributed to gas-side corrosion. There was corrosion under insulation as well. The plant entered permanent shutdown in 2015.
Specific HRSG defects were shown to meeting participants—including the lack of penetration on tube-to-header welds, tube-to-header misalignments, and general poor weld quality. Acceptance criteria also were clearly defined.
The primary Otahuhu message: Challenging risks can be managed over time with an active and flexible approach. A wait-and-see attitude will not work. This put emphasis on Steering Committee Member John Blake’s “Don’t just set and forget” caution earlier in the day.
Steam valve damage
Operational changes also can lead to hardware issues deep inside system components. At Darling Downs, explained by Origin’s Pieter Wessels, valve damage seems to have occurred in the first 60 seconds of operation below the saturation line, with water going through the valve. The 630-MW power station (Fig 6) in Queensland was commissioned in 2010 with three GE Frame 9E turbines, three HRSGs, a 270-MW GE steamer, and an air-cooled condenser.
First inspection of the main steam valve was in May 2014, five months before the first steam-turbine minor. The unit’s two main-steam stop valves, configured as combined stop and control valves with a common seat, were arranged in parallel. The inspection revealed damage to both stop-valve stems. Important to note is that Darling Downs had converted to cycling operation.
Stem damage (Fig 7) was attributed to plastic deformation, erosion, and/or corrosion.
HP-bypass DRAG® valves were inspected in October 2014. Inconel 718 disk stacks had significant damage on all units (Fig 8).
Repairs and actions were both short- and long-term.
For the stop valves, both stems were replaced and the plant increased its stock level from one stem to two. Operational actions included daily on-load valve-gear testing. Control-valve throttling was avoided by increasing minimum station load by approximately 10 MW and by continuous monitoring.
For the long term, control-valve throttling avoidance continued. Additional inspections at 12,000 to 15,000 hours determined the need to install a modified seat and install a modified control-valve head assembly.
For the bypass valves, short-term repair included turning all disc stacks 90 degrees, purchase of replacement disc stacks, and a review of HRSG startup procedures. For the longer term, stacks would be replaced at 12,000 to 15,000 operating hours and a design change would enhance HRSG superheater manual drainage. This would improve blowdown at shutdown (removing magnetite) and improve drainage at startup (removing water).
Phased-array inspection of complex components
Chris Charlesworth, ALS Australia, offered insights into ultrasonic inspection techniques for complex shapes, such as root serrations of turbine blades. The phased-array inspection of complex components, he explained, can be enhanced through validation reports, procedure development, and other methods based on CAD models. The speaker said parametric CAD models speed up the inspection development (and approval) process.
Samples with known defects also can be developed to test the methodologies and tools. Rapid prototyping was beneficial in the examples described.
Time span for development, from scope definition to final inspection launch, can be as little as two to three weeks. Dooley suggested that linking this inspection technique with site chemistry would help to understand the root cause of the defect.
Expansion joints also must adjust to change
Consistent with other presentations, expansion joints are affected by a change in operations. For gas-turbine outlet fabric joints, as an example, cycling can increase thermal stress and cause cracks, hotspots, and fabric failure.
Dekomte’s Jon Terrant addressed fabric expansion-joint technology for HRSG inlets and outlets, penetration seals, air intakes, and gas-turbine exhaust applications. These joints, the speaker said, reduce gas leakage, air ingress, and a host of related short- and long-term concerns.
Two-shifting and cycling have perhaps the largest destructive impact on expansion joints and require review of equipment in these new modes of operation. Results can include duct-temperature gradients, duct fatigue and stress caused by these gradients, irregular stresses caused by movement, and both acid and water dew-point condensation.
In just one example, the inlet joint on a hot casing will be impacted by inside dimension, gas velocity and pressure, axial and lateral movement, thermal transients, stress, and cycles (normal starts). Short-term solutions could include weld repairs to frame and duct, regular replacement of fabric, and external insulation. Long-term solutions are more complex:
- New steel part arrangement.
- Improved duct interface.
- New external insulation.
- New fabric and bolster design.
- New fixing and convector design.
Material options were also given, particularly for HRSG outlets. These included double-coated PTFE fabric, a single layer of EPDM/Viton, and multi-layer joints with a Viton gasket sealing the flange. Related component designs were then reviewed.
Penetration seals attracted strong attention, along with the pros and cons of both OEM and retrofit designs. The most common OEM offerings are metal bellows, packed gland seals, mechanical seals, and fabric seals. Retrofits include metal bellows, mechanical seals, and fabric.
This session ended with an interesting discussion on pumpable insulation. This is a viable fix when thermal surveys reveal casing hotspots (Fig 9). The cause normally is movement or decay of internal insulation materials.
Pumpable insulation can be injected online and monitored through thermal imaging as it spreads. This is a low-risk option to insulation replacement. The selected material, Isofrax®, has low thermal conductivity, good strength and vibration resistance, and can withstand temperatures up to 2300F. The material can be removed, and injection ports (Fig 10) can be reused.
Chemistry to support flexible operation
Flexible plant operation impacts HRSG chemistry. New Zealand-based David Addison, principal, Thermal Chemistry, began Day Two with optimized cycle chemistry, stating: “If baseload HRSG (cycle) chemistry is not optimized, it will never be optimized for flexible operation.” The theme of operational change would continue from Day One, so Addison set clear definitions:
- Almost always online, steady load, high load factor.
- Infrequent starts, mainly cold starts.
- Frequent stops and starts.
- Large load changes (load following) during operation.
- Plants able to have accelerated hot, warm, and cold starts.
- Used with both once-through and drum-type HRSGs.
- Appropriate for two-shifting/cycling operation.
As discussed on Day One, flexibility is critical in today’s power generation market. This includes the new world of fossil generation impacted by solar and wind generation, and in Australasia geothermal to some degree.
Addison further set the stage for cycle chemistry’s challenges:
- Sampling and analysis systems must produce a quality sample within the flows and pressures required.
- Dosing systems must establish control and set points.
- Blowdown and water demand will strain the water treatment plant.
- Risk of condenser tube leaks will rise with cooling-water pump starts and bypass operations.
- Availability of plant personnel will be stretched; everyone will be busy.
Large load swings
- There will be pressure and flow issues, phosphate hideout, and carryover.
A good starting point, stated Addison, is the IAPWS optimized program and readily available (and free) IAPWS Technical Guidance Documents (TGD).
Standard base parameters were then listed:
- Feedwater, AVT(O) or OT (oxygenated treatment).
- LP evaporator drum (feedforward), AVT(O) or OT.
- LP/IP/HP evaporator (once-through), OT.
- LP/IP evaporator drum (standalone), phosphate treatment (PT) or caustic treatment (CT).
- HP evaporator drum, AVT(O) or PT/CT.
- Instrumentation (refer to IAPWS TGD, available at www.iapws.org).
- Carryover testing (refer to IAPWS TGD).
- Corrosion-product sampling and analysis (refer to IAPWS TGD).
For dosing, the standard is AVT(O) or OT feedwater chemistry with no oxygen scavenger used at any time. AVT(O) should provide 5 to 10 ppb dissolved oxygen.
Feedwater pH control is critical, and the fully automatic control loop should maintain a 9.8 control point under all startup and operating conditions.
Evaporator pH control also is critical. Automatic phosphate or caustic control ensures stable evaporator pH and minimizes over- or under-dosing issues.
pH control is critical, too, for controlling single- and two-phase flow-accelerated corrosion (FAC) control and to minimize the risk of contaminates in the system.
With phosphate treatment, hideout can be a challenge, particularly above 1450 to 1520 psig. Fast starts and load changes can aggravate the situation in some HRSG designs. If using trisodium phosphate only, no corrosion issues are caused by hideout. But with mono- or di-sodium phosphate there is major acid phosphate corrosion risk. Therefore, the standard recommendation is TSP only.
Phosphate should be maintained above 0.3 ppm for minimum protection, along with proper pH for FAC protection. If there is a need to go lower (phosphate) then NaOH can be added. Sometimes, a conversion to caustic treatment (with no hideout issues) is needed. The IAPWS TGD provides clear guidance on this in Section 6.4.
Once-through HRSGs are suited to flexible operation with AVT/OT chemistry. They do, however, require proper condensate polishing for correct feedwater quality.
Sampling and analysis. Addison then turned to sampling and analysis. Minimum instrumentation should be in line with the IAPWS TGD (2015 revision) which includes fast- start/flexible HRSG advice in Section 4.7:
- Automatic analyzer water flushing.
- Short sample lines/local sample conditions.
- Degassed conductivity (CACE) on condensate and superheated steam.
Corrosion products. It is critical to know total iron levels, a key chemistry parameter. IAPWS is currently working on more guidance for flexible operating regimes.
Carryover. Perhaps the most robust discussion centered on carryover (Fig 11). For HRSGs with drums, flexible operation leads to high carryover risk, which is conducive to superheater and steam-turbine damage. This risk increases during startups and rapid changes in load. Thus drum level control is critical and should be fully validated against saturated-steam analysis and carryover testing (in line with IAPWS TGD). Continuous online saturated-steam sampling, and CACE and sodium analysis, are strongly recommended.
In general, carryover increases with HRSG operating pressure. Simple steam-drum designs have higher carryover limits, but offer poorer steam purity. Lower drum pressures reduce the carryover risk, but risks escalate with fast starts and flexible operation.
Consistent with others, Addison stressed the importance of proper layup and storage procedures and equipment. In summary, short-term wet layup of an HRSG requires nitrogen capping; long-term wet layup requires nitrogen capping, HRSG circulation, mechanical dissolved oxygen control, and pH control. Dry storage for both the HRSG and steam turbine requires automatic dehumidification systems.
Seventy percent of combined-cycle plant damage can be traced to poor chemistry, which contributes to tube failures via FAC, under-deposit corrosion, corrosion fatigue, stress corrosion cracking, and pitting. Corrosion-product transport leads to deposits in HP evaporators and steam turbines, and in air-cooled condensers. Steam-turbine damage in the phase-transition zone results from pitting, stress corrosion, and corrosion-fatigue cracking. Damage also results from deposition in the HP, IP, and LP sections.
Traditional searches for cause looked at HRSG design, turbine design, and feedwater system design. But it is now apparent that other causal elements were missing. Plants can be at fault by:
- Not addressing cycle chemistry basics.
- Not installing a fundamental level of instrumentation.
- Not using the international standards of cycle chemistry.
- Not using total iron as an indicator.
- Not having an integrated management program to prevent repeat cycle-chemistry situations.
Identification of repeat cycle-chemistry situations is a powerful (yet still overlooked) tool. Dooley then reviewed plant assessments using repeat cycle-chemistry analysis, leading to categories within these recurring situations. Tied for first position are corrosion products and instrumentation. Next was drum carryover, followed by failure to challenge the system chemistry status quo, then HP evaporator deposits.
An alarming fact: 37% of HRSGs worldwide are using reducing agents, at very high risk.
Bob Anderson, principal, Competitive Power Resources Corp, Palmetto, Fla, recognized globally for his HRSG expertise, offered a thermal-transient assessment update. Common issues included small drain pipes, blowdown vessels located above headers, and drainage control not based on condensate detection. Anderson noted that only a few plants have a robust root-cause process for failures related to thermal transients.
Many questions and discussions followed as meeting attendees wrestled with data presented by the speaker and its implications for their plants. Interesting points were made about OEM ramp rates, drum and header thicknesses, numbers of tubes, thermocouples, and other specifics, showing the complexity of thermal transients and the assessments.
High energy piping
Chris Jones of Quest Integrity Group stressed three critical stages for a proper piping analysis process: pre-outage, outage, and post-outage. Jones presented a case study of high-energy pipe weld defects with changes over time, and a fitness for service assessment using finite-element analysis.
A key modeling parameter is content: Does it include adjacent defects, or is each defect treated separately? The case presented showed how analysis helped determine fitness for service, centering on creep damage. Local repair was possible.
Discussions followed specific to finite-element analysis.
Legislative and standards updates were given for HRSG owners and operators throughout Australia and New Zealand. Pressure equipment regulations vary state by state, and a complex layer of codes is in force. Standards are being updated, reviewed, and drafted. The move to greater penetration of international standards, in some cases, is being held back by the slowdown in domestic manufacturing.
Darren Sullivan, an ALS plant inspection manager, offered the review, concentrating on pressure parts and safety management systems. For conference attendees, there seemed to be an opportunity to input directly into this process or seek clarification related to HRSGs.
Newly revised pressure equipment standards were listed for conformity assessment (AS 3920:2015), for hazard levels (AS 4343:2014), and for welding and brazing qualification (AS/NZS 3992:2015). ASME and selected international standards were also discussed.
In summary, Sullivan encouraged attendees to participate, through the AHUG Forum, to ensure proper HRSG presence.
Control of SH/RH drains
Anderson, a member of the steering committee, then addressed the industry’s ongoing issues with superheater and reheater drains and how ultrasonic flowmeters and good design and procedures can help mitigate them. Here’s what he suggested:
For startups from 0 psig (simple).
- Drain pipes must be large enough (gravity head only).
- Discharge must be below point of origin.
- All drains must be open before purge to ensure the superheater is empty.
- Drains should remain open during purge.
- Drains should be closed when pipe temperature downstream of control valve exceeds Tsat + ~80 deg F for 30 seconds.
- Time is available for draining before steam flow begins.
- A limited quantity of condensate is generated at 0 psig.
Pressurized startup (complex).
- More condensate is generated.
- Very little time is allowed from gas turbine fire to initial steam flow.
- Drain flow varies greatly with pressure.
- Opening drains for long periods can result in excessive drum pressure decrease and blowdown system temperature/flow changes.
- Water detection is critical to minimize steam release during purge. Bear in mind that thermocouples cannot detect water.
Various methods for detecting water were reviewed, including an ultrasonic system using the transit-time technique (Fig 12). An EPRI prototype drain control system, installed on three HRSGs to date, was then examined (Fig 13).
Current installations cover several pipe sizes and materials plus different configurations. The Flexim Americas Corp fluid detector described in Fig 12 calculates signals to correlate the noise ratio of ultrasonic sound waves passing between transducers. DCS logic then controls the drain valves. Development and testing of this system continues.
Dooley, executive secretary of IAPWS, and Gary Joy, chairman of the Australian national committee for IAPWS, ended Day Two with an update of that organization’s activities and by reminding participants of the value of its Technical Guidance Documents. Updates of greatest interest to readers were the following:
- A TGD on film-forming amines will be released in 2016 and will include specifics on their safe and effective use.
- The TGDs on instrumentation and treatment for fast-start and frequently started HRSGs, published June 2015, are being updated.
- The TGD “HRSG HP Evaporator Sampling for Internal Deposit Determination” will be published in 2016. CCJ