Welcome back! It’s been a while since I’ve posted here. Been buried with client requests… there are worse problems to have, I suppose.
This summer’s focus is INSTRUMENTATION.
I’ll be digging into the instrumentation requirements for combined cycle facilities, looking at what instrumentation you’re likely to have on site, what accuracy and uncertainty you can expect for your key performance indicators (such as GT compressor efficiency, ST sectional efficiencies and overall plant net heat rate), and the cost to add instrumentation – especially those items you very likely don’t currently have (such as an accurate weather station or gas chromatograph).
So… please post any suggestions, comments or questions regarding instrumentation here on this blog entry, or jot me an email direct.
I’d love to hear from you about what your current issues are regarding instrumentation:
* How often do you calibrate devices not required by controls?
* What manual inputs do you make (or try to make) on a regular basis? (i.e. HHV)
* What roadblocks do you run into when trying to add instrumentation?
And check back here for updates. Hopefully more often than once a year!
I hope you all enjoy your summer.
There’s a great waterwash discussion going on the Gas Turbine Users Group on LinkedIn.
The Question was posed by an LM6000 user, but responses could apply to any engine compressor.
Combined Cycle Journal posted an article yesterday (4/14/11) regarding a potential safety hazard on the 7FA liquid fuel lines – even when the unit is not a duel fuel unit, and fired natural gas only.
A leak around a blank flange on an unused liquid fuel port led to a pressure reduction in the combustion chamber – which allowed the flame to move back and attach to the fuel nozzle itself. Once the flame was attached, severe material deterioration occured.
The details, including pictures and recommendations are included in their article, here. If you operate any 7FA’s – on any fuel – I recommend you take a look at the article’s findings.
There’s a great article in this month’s Power Engineering magazine:
“Proper Calibration of Gas Analyzers” by Terrence Kizer.
(October 2010, starts on page 22)
It points out some of the options for CEMS calibration gas cylinders and how the analyzers use them to monitor for analyzer drift.
You should also check on your natural gas chromatograph calibration gas cylinders (if you have an onsite chromatograph) – the closer the calibration gas is to your actual pipeline gas, the more accurate the resulting analysis will be. If you’re still using the same calibration gas determined during site development, you might want to take a second look. Pipeline gas can shift from season to season, and if your calibration gas is significantly different than actual, the accuracy of the reported heating values will be affected.
If your chromatograph is also used for billing purposes – you’ll want to make double sure the calibration gases are correct. Even a 0.2% increase in a plant fuel bill can be a very large number!
A colleague recently asked a very important question:
How often should instruments be calibrated?
Many sites have requirements for calibration on certain instruments – such as fuel flow meters used for emissions reporting. But what about the rest?
Any sensor – temperature, pressure, flow, etc. – which provides input into your control system should be monitored regularly for accuracy. Things such as compressor inlet temperature, compressor discharge pressure and exhaust temperature – to begin with – all play a part in the load control of every type of gas turbine.
Annual calibrations are normally a good starting point – they provide you with a baseline for how each instrument changes over time. Reviewing these calibrations will give you a better understanding of how the working environment is impacting each sensor. In certain high stress applications – such as compressor discharge pressures on peaking units – calibrations and instrument adjustments may be needed more frequently than once a year. In low stress environments – such as cooling water temperatures – annual may be more than needed. But, if you lower the frequency of calibrations to less than annually, you may need to adjust your low-level alarm points to more readily catch instrument drift failures.
Please share how often you calibrate your site instrumentation here – I’d love to hear what your policies are. Do you calibrate all sensors or just a select few? Annually? Semi-annually (i.e. during each spring and fall outage)? Or “as needed”?
Do you utilize software tools, such as pattern recognition, to adjust your instrument calibration schedules?
I look forward to reading your replies.
I’m reminded again about the importance of instrumentation.
Fuel metering – especially billing meters – are expected to be infallable. But I’ve just seen another case where the revenue class meter is not reading correctly. And this is not the first time this year this problem has come up.
It’s important to have backup metering for your fuel bill in order to know that your bill is accurate – and to help alert you to when any of your meters on site may need attention.
Often it’s the plant’s gas turbine meters that are required to be calibrated every year for emissions reporting… but the billing meter only gets looked at if someone asks. So, I recommend you keep tabs on those billing meters and if something looks strange – ask!
And, on a performance note – if your fuel flow metering is off, your reported heat rate will also be off. For some of you this is just an accounting problem, but for others, this may impact your dispatchability in the future.
I am available to help with fuel flow calculations, and have add-ins to support flow calculations and fuel properties within Excel. If you have any questions – please ask me, I’m here to help!