Boiler Research Project - ASHRAE Standard 155P – Phase II Boiler Research Testing_12...Dec 21,...

PG&E’s Emerging Technologies Program ET11PGE5272

Boiler Research Project - ASHRAE Standard 155P – Phase II ET Project Number: ET11PGE5272 (Sample picture of product/technology

Project Manager: Ed Elliott Pacific Gas and Electric Company Prepared By: Al Beliso Eddie Huestis Manny D’Albora PG&E – Applied Technology Services 3400 Crow Canyon Rd. San Ramon, CA 94583 Jeff Stein / Kathleen Matthews Taylor Engineering

Issued: December 21, 2012

ã Copyright, 2012, Pacific Gas and Electric Company. All rights reserved.


ACKNOWLEDGEMENTS Pacific Gas and Electric Company’s Emerging Technologies Program is responsible for this project. It was developed under internal project number ET11PGE5272. Applied Technology Services conducted this technology evaluation for Pacific Gas and Electric Company with overall guidance and management from Ed Elliott. For more information on this project, contact [email protected].

LEGAL NOTICE This report was prepared for Pacific Gas and Electric Company for use by its employees and agents. Neither Pacific Gas and Electric Company nor any of its employees and agents:

(1) makes any written or oral warranty, expressed or implied, including, but not limited to those concerning merchantability or fitness for a particular purpose;

(2) assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, process, method, or policy contained herein; or

(3) represents that its use would not infringe any privately owned rights, including, but not limited to, patents, trademarks, or copyrights.


FIGURES Figure 1. Unit 2 Test Results for Sensor Combination TS1/TR1, 800

CFH Meter .................................................................. 9

Figure 2. Modular Rack Assembly WIth Instrumentation Under Construction Inside Environmental Chamber ................. 12

Figure 3. Flex Line for ease of Installation and Removal of Individual Test Units .................................................. 13

Figure 4. Insulated Modular Rack Assembly WIth Instrumentation Under Construction Inside Environmental Chamber ........ 13

Figure 5. Schematic of Test Apparatus ....................................... 15

Figure 6. Schematic of Boiler Load Rejection/Tie In With Coriolis Flow Loop ................................................................. 15

Figure 7. Badger M2000 Magnetic Flow Meter ............................. 21

Figure 8. HART 9105 Hot Block With Temperature Standard Probe and Test Instrumentation Inserted ............................... 25

Figure 9. KAYE HTR-600 Hot Block With Temperature Standard Probe and Test Instrumentation Inserted ...................... 25

Figure 10. Fluke Temperature Reference Standard (PG&E #30032) . 26

Figure 11. Boiler Inlet Temperature 1 Measurement Array (RTD Center, Thermocouples Surrounding) ........................... 28

Figure 12. Boiler Inlet Temperature 2 Measurement ...................... 28

Figure 13. Boiler Inlet Temperature 3 Measurement ...................... 29

Figure 15. Boiler Outlet Temperature 2 ........................................ 31

Figure 16. Ametek PKII Dead Weight Tester (Pressure Calibration Standard) ................................................................ 33

Figure 17. Calibration of Rosemount Pressure Transmitter Using Dead Weight Tester ................................................... 34


Figure 19. Calibration Curve of Natural Gas Volumetric Flow Meter .. 38

Figure 20. 1500 Cubic Foot Per Hour Capacity Natural Gas Violumetric Flow Meter ............................................... 39

Figure 21. 800 Cubic Foot Per Hour Capacity Natural Gas Violumetric Flow Meter ............................................... 39

Figure 22. Both Natural Gas Volumetric Flow Meters with 800 CFH Meter Bypass Loop .................................................... 40



Figure 24. Flue Gas Thermocouple Grid Arrangement................... 47

Figure 25. Location of Flue Gas Temperature and CO2 Sampling .... 48

Figure 26. LANCOM III Exhaust Gas Analyzer Used for Taking Flue CO2 Measurements ............................................. 49

Figure 27. Unit 1 with Sidepanels ................................................ 57

Figure 28. Unit 1 without Sidepanels ............................................ 58

Figure 29. Units 2 Steady State Test Results ................................. 59

Figure 30. Unit 2 Test Results for Sensor Combination TS1/TR1, 800 CFH Meter .......................................................... 60

Figure 31. Overall Uncertainty for Each Sensor Combination for Test 2.01.00 ............................................................. 61

Figure 32. Unit 1 Steady State Test Results .................................. 62

Figure 33. UNIT 1 TEST RESULTS FOR SENSOR COMBINATION TS1/TR1, 800 CFH METER .......................................... 62

Figure 34. Overall Uncertainty and Uncertainty Constituents for 2.01.00 Sensor Combination TS1/TR1, 800 Meter .......... 64

Figure 35. Deviation (% of Indication) Between Coriolis Standard and Magnetic Flow meter Without Calibration Data Processing Correction ................................................. 69

Figure 37. Comparison Between Raw and Corrected Deviation (% of Indication) Between Coriolis Standard and Magnetic Flow meter ............................................................... 70

Figure 40. Four Sampling Locations Along the Burner of Unit 1 ...... 73

Figure 41. Concentration of Carbon Dioxide in Flue Gases of Atmospheric Boiler With Four Different Sampling Locations Along the Burner for Test 1.02 ...................... 74

Figure 42. Mixing Verification Array End Cap ............................... 75

Figure 43. Efficiency Snapshots for 2.01.01 (High Fire, High Temperature) ........................................................... 81

Figure 44. Efficiency Snapshots for 2.04 (Low Fire, Low Temperature) ........................................................... 82

Figure 45. Average Water Temperature During 2.04 and 2.05 ......... 84

Figure 46. Efficiency and Uncertainty for 2.04 and 2.05 .................. 85

Figure 47. MIXING TEST SETUP - 4 ELBOWS ................................. 88

Figure 48. MIXING TEST SETUP - STRAIGHT PIPE .......................... 88

Figure 49. MIXING TEST SETUP - 4 TEES ...................................... 89


TABLES Table 1. Calculated Uncertainty vs. Required Uncertainty .............. 9

Table 2. Summary of Test Units ............................................... 15

Table 3. Summary of Tests ..................................................... 16

Table 4. Std. 155P Water Volumetric Flow Requirements ............. 19

Table 5. Identifying Sources of Error in Water Volumetric Flow Rate ........................................................................ 21

Table 6. Resulting Uncertainty In Water Volumetric Flow Rate ...... 22

Table 7. Identifying Sources of Error in Water Density ................ 23

Table 8. Resulting Uncertainty In Water Density ........................ 23

Table 9. Std. 155P Water Temperature Instrumentation Requirements ........................................................... 23

Table 10. Identifying Sources of Error in Temperature Instrumentation ........................................................ 26

Table 11. Resulting Uncertainty In Temperature Measurement ....... 27

Table 12. Std. 155P Pressure Instrumentation Requirements ......... 31

Table 13. Identifying Sources of Error in Gas Pressure Instrumentation ........................................................ 35

Table 14. Resulting Uncertainty In Gas Pressure Instrumentation ... 36

Table 15. Identifying Sources of Error in Barometric Pressure ........ 36

Table 16. Resulting Uncertainty In Barometric Pressure Instrumetation .......................................................... 37

Table 17. Std. 155P Natural Gas Volumetric Flow Measurement Requirements ........................................................... 37

Table 18. Identifying Sources of Error in Natural Gas Volumetric Flow Rate ................................................................. 40

Table 19. Resulting Uncertainty In Natural Gas Volume Meter ........ 40

Table 20. Std. 155P Natural Gas Energy Content Measurement Requirements ........................................................... 41

Table 21. Analyzing Standard Deviation in Weekly HHV Values ...... 41

Table 22. Std. 155P Boiler Auxiliary Power Measurement Requirements ........................................................... 42

Table 23. Identifying Sources of Error in Boiler Auxiliary Power Measurement ............................................................ 43

Table 24. Resulting Uncertainty In Boiler Auxiliary Power Input ...... 43

Table 25. Std. 155P Mixing Pump Auxiliary Power Measurement Requirements ........................................................... 44


Table 26. Identifying Sources of Error in Mixing Pump Auxiliary Power Measurement .................................................. 44

Table 27. Resulting Uncertainty In Mixing Pump Auxiliary Power Input ....................................................................... 44

Table 28. Std. 155P Flue Carbon Dioxide Concertration Measurement Requirements ........................................ 48

Table 29. Identifying Sources of Error in Flue Gas Carbon Dioxide Measurement ............................................................ 49

Table 30. Resulting Uncertainty In Percentage of CO2 Instrumetation .......................................................... 49

Table 31. Std. 155P Relative Humidity Measurement Requirements ........................................................... 50

Table 32. Identifying Sources of Error in Relative Humidity Measurement ............................................................ 50

Table 33. Resulting Uncertainty In Relative Humidity Measurement ............................................................ 50

Table 34. Comparison of Test 2.01.00 Measurement Parameter Uncertainty to Std. 155P Requirements ........................ 63

Table 35. Dithering Temperature Measurement Uncertainty ........... 65

Table 36. Dithering Measurement Uncertainty – Test 2.01.01 ........ 66

Table 37. Uncertainty In Std 155P - High Fire, High Temperature Test (No Condensate Formation) ................................ 67

Table 38. Uncertainty In Std 155P - High Fire, High Temperature Test (No Condensate Formation) ................................ 67

Table 39. Uncertainty In Std 155P - High Fire, Low Temperature Test (Condensate Formation Occurs) ............................ 68

Table 40. Uncertainty In Std 155P - High Fire, Low Temperature Test (Condensate Formation Occurs) ............................ 68

Table 41. Comparison of Thermal Efficiency Calculation Using Either Raw or Corrected Data ...................................... 71

Table 42. Impact of Easing Natural Gas Volumetric Flow Accuracy Requirement on Overall Uncertainty ............................. 72

Table 43. Impact of Easing Natural Gas Higher Heating Value Accuracy Requirement on Overall Uncertainty ................ 72

Table 44. Impact of Spatial Uncertainty In Atmospheric Boiler on Overall Uncertainty of Combustion Efficiency ................. 74

Table 45. Impact of Sampling Interval on Overall Thermal and Combustion Efficiency ................................................ 75

Table 46. Jacket Loss Results .................................................... 75


EQUATIONS Equation 1. Calculation of precision error resulting from

repeatability in calibration of instrumentation. ............... 18

Equation 2. Calculation of fossilized bias error resulting from repeatability in calibration of instrumentation. ............... 18

Equation 3. Calculation of precision error resulting test data fluctuations. ............................................................. 18

Equation 4. Boiler Thermal Efficiency Calculation ............................ 19

Equation 5. Boiler steady state combustion efficiency .................... 45

Equation 6. Flue Losses, Lf ......................................................... 45

Equation 7. Steady State Latent Heat Gain due to Condensation in flue ......................................................................... 45

Equation 8. Steady State Latent Heat Gain due to Condensation in flue ......................................................................... 45

Equation 9. Calculation of C1, C2, C3 and C4 .................................. 45

CONTENTS FIGURES _______________________________________________________________ 2

TABLES ________________________________________________________________ 4

EQUATIONS _____________________________________________________________ 6

CONTENTS _____________________________________________________________ 6

EXECUTIVE SUMMARY _____________________________________________________ 9

INTRODUCTION _________________________________________________________ 10

TEST METHODOLOGY ____________________________________________________ 11

Boiler Setup ........................................................................ 11

Difficulty Tuning Unit 2 ......................................................... 15

Test Plan ............................................................................. 15

Instrumentation Plan ............................................................ 16

Steady State Thermal Efficiency Test Parameters ................. 16 Steady State Combustion Efficiency Test Parameters ............ 17


Establishing Uncertainty in Measurement of Test Parameters ...... 17

Water Volumetric Flow Rate .............................................. 19 Water Density ................................................................. 22 Temperature Measurement ............................................... 23 Boiler Water Inlet Temperature ......................................... 27 Boiler Water Outlet Temperature ....................................... 29 Natural Gas Volumetric Flow Compensation Temperature ...... 31 Pressure Measurement ..................................................... 31 Natural Gas Volumetric Flow Compensation Pressure ............ 34 Barometric Pressure ........................................................ 36 Non-Compensated Natural Gas Volumetric Flow Rate ............ 37 Natural Gas Higher Heating Value ...................................... 41 Boiler Auxiliary Power Input .............................................. 42 Mixing Pump Auxiliary Power Input .................................... 44

Steady State Combustion Efficiency Test Parameters ................. 45

Burner Inlet Temperature ................................................. 46 Flue Gas Temperature ...................................................... 46 CO2 Concentration .......................................................... 48 Relative Humidity ............................................................ 50

Jacket Loss Test Procedures ................................................... 51

Unit 2 ............................................................................ 54 Unit 1 ............................................................................ 56

Idling Tests ......................................................................... 58

RESULTS ______________________________________________________________ 59

Unit 2 Steady State Test Results ............................................ 59

Unit 1 Steady State Test Results ............................................ 61

Test Disqualification ............................................................. 63

Uncertainty Analyses ............................................................ 63

Summary of Uncertainty in Each Measured Parameter .......... 63 Dithering Test Parameter Uncertainty ................................. 64 Uncertainty in Std. 155P Requirements .............................. 67 Understanding and Mitigating Water Flow Uncertainty ........... 69 Understanding and Mitigating Gas Volumetric Flow

Uncertainty ............................................................... 72 Understanding and Mitigating Higher Heating Value

Uncertainty ............................................................... 72 Understanding and Mitigating Flue CO2% Uncertainty ........... 73 Temperature Instrumentation Operational Checks ................ 74 Mixing Verification Temperature Array ................................ 74 Impact of Sampling Interval on Test Uncertainty .................. 75

Jacket Losses ...................................................................... 75

Idling Test Results ................................................................ 76

OBSERVATIONS _________________________________________________________ 79


Additional Uncertainty in Combustion Efficiency ........................ 79

Miscellaneous ...................................................................... 79

EVALUATIONS __________________________________________________________ 80

Efficiency Snapshots ............................................................. 80

Natural Gas Temperature Spatial Uncertainty ........................... 82

Effect of a Throttling Valve on Thermal Efficiency ...................... 83

RECOMMENDATIONS ____________________________________________________ 85

Recommended Changes to Standard 155P ............................... 85

Recommended Future Research ............................................. 87

Mixing Devices ................................................................ 87 Thermal Efficiency Uncertainty .......................................... 89 Ambient Temperature Effects And New Test Procedures ........ 90 Dynamic Boiler Testing..................................................... 90 Spreadsheet Development ................................................ 92

APPENDICES ___________________________________________________________ 93

Boiler Water Volumetric Flow ............................................ 93 Temperature Standard ..................................................... 95 800 CFH Natural Gas Meter Calibration Report ..................... 98 1500 CFH Meter Calibration Report .................................... 99


EXECUTIVE SUMMARY In this phase of the PG&E Boiler Project a new test stand was built and a number of steady state tests were run on two boilers in order to investigate uncertainty in thermal efficiency measurements. Boiler Unit 1 is an outdoor atmospheric boiler. Unit 2 is a forced draft condensing boiler. Combustion efficiency and jacket losses were also measured as well as the uncertainty in combustion efficiency and jacket losses. A number of ancillary analyses were also performed including some idling tests.

Figure 1 is a sample of the results. All quantifiable bias and precision error components of all sensor measurements were root sum squared to arrive at an overall uncertainty (represented by error bars in Figure 1). Similarly a root sum squared analysis was performed using all the required sensor accuracies in Standard 155P to determine the required overall uncertainty.

FIGURE 1. UNIT 2 TEST RESULTS FOR SENSOR COMBINATION TS1/TR1, 800 CFH METER

Some of the Phase II Test Bed sensors were slightly more accurate than required by 155P, others were slightly less accurate but the overall uncertainty was within the range required by Standard 155, as shown in Table 1.

TABLE 1. CALCULATED UNCERTAINTY VS. REQUIRED UNCERTAINTY

Overall Uncertainty (+/- % absolute efficiency)

Standard 155 Phase II Test Bed

high fire, high temp (no condensate)

Thermal Efficiency 1.11% 1.02% Combustion Efficiency 0.23% 0.26%

high fire, low temp (yes condensate)

Thermal Efficiency 1.14% 1.04% Combustion Efficiency 0.31% 0.41%


We are fairly confident the thermal efficiency uncertainty has been fully captured. There is a good chance, however, that there is additional uncertainty in the combustion efficiency uncertainty that is not captured. For example, combustion uncertainty does not account for variations in CO2 concentration within the flue. The combustion efficiency equation also has imbedded assumption like HHVgas. The expression “better the devil you know, than the devil you don't” comes to mind when comparing thermal and combustion efficiency. Thermal efficiency uncertainty may be higher than we would like but we can be reasonably confident in that uncertainty. Combustion minus Jacket is likely to have additional unknown uncertainty.

Furthermore, flue measurements on Unit 1 showed that combustion efficiency cannot be measured with any reasonable accuracy on boilers without ducted flues. Similarly, jacket loss measurements on both units showed that jacket losses also cannot be measured with any reasonable accuracy for boilers with complex geometry and ambiguous jackets (e.g. controls enclosures, vented side panels). Even though jacket losses may be small compared to total input/ouput, including rating procedures for jacket losses in 155P could lead to misleading and unwarranted claims like “our boiler has half the rated jacket losses of our competitors”. Thermal efficiency, on the other hand, can be measured with reasonable accuracy and confidence for any boiler.

The recommendations section of this report includes several recommendations for changes to Standard 155P that should improve thermal efficiency accuracy without adding considerable cost or testing burden, such as: (1) gas temperature must be measured close to the gas meter and piping must be insulated to insure the temperature in the meter is accurate, and (2) reduce the sampling interval from 15 minutes to 1 minute. Recommendations are also included herein for future research, such as: (1) testing of mixing devices in order to reduce the mixing verification testing burden, and (2) additional testing to investigate and reduce thermal efficiency uncertainty.

INTRODUCTION This is the final report for 2012 phase (Phase II) of the boiler research performed at PG&E’s Applied Technology Services (ATS) in support of ASHRAE Standard 155P. Standard 155P, “Method of Testing for Rating Commercial Space Heating Boiler Systems”, has been under development by ASHRAE for over 17 years. Standard 155P is sorely needed by the HVAC industry because there is no standard for rating the performance of commercial boilers at part load conditions (where most boiler operate most of the time) or at realistic entering water temperatures. BTS-2000 is the current standard used by the industry but it only rates boilers at full load and only at unrealistically low entering water temperatures. Standard 155P will allow engineers, manufacturers, owners, policy makers, simulation software developers and others to objectively evaluate and compare the true performance of boilers. This will lead to better HVAC designs, better boiler designs, better utility incentive programs, better energy codes, etc.—all of which will lead to significant natural gas savings and emissions reductions.

The primary goal of the boiler research at ATS has been to support ASHRAE in overcoming the remaining technical questions that are hindering the completion of Standard 155P. Phase I of the boiler research at ATS was completed in late 2011. It focused on identifying any fundamental flaws in the test methodology, calculation procedures and report forms. No fundamental flaws were identified but several minor flaws and recommendations were


identified, such as the need to address stratification. The Phase I report is available at: http://www.etcc-ca.com/images/boiler_research_project_-_ats-te_final_report_pcb_05092012.pdf

After the Phase I research was completed several new technical concerns emerged among members of the 155 committee. The biggest question raised was: Can thermal efficiency be measured directly (btuh output/ btuh input) with reasonable accuracy at a reasonable cost, or is it more accurate and easier to measure thermal efficiency indirectly by measuring combustion efficiency and jacket losses? This question was the main focus of the Phase II research. Phase II objectives included:

1. Set up a Standard 155-compliant test stand with high accuracy but reasonably priced sensors, using redundant sensors, where practical, to improve confidence in results.

2. Calibrate the sensors using good calibration practices.

3. Run serveral steady state tests and calculate uncertainty in thermal efficiency, combustion efficiency and jacket losses.

4. Look for patterns between between thermal efficiency, and combustion efficiency minus jacket losses which might inform when it is appropriate or not appropriate to use one as proxy for the other.

Other issues investigated in Phase II included:

5. Idling Test Stability

a. How many warm up cycles and test cycles are necessary to achieve a reasonably stable idling rate?

b. Can using a small differential reduce total test time without significantly increasing uncertainty?

6. Stability of thermal and combustion efficiency between sub-intervals within the 2 hour steady state tests.

7. Additional uncertainty in combustion efficiency, such as spatial uncertainty in CO2 concentration and assumptions imbedded in the combustion efficiency equation, such as HHV.

TEST METHODOLOGY BOILER SETUP

All testing was performed in the Advanced Technology Performance Lab at PG&E’s San Ramon Technology Center located at 3400 Crow Canyon Rd. in San Ramon, CA. Boiler test units were placed in an environmental chamber where ambient conditions were controlled during each test. Water is fed to each test unit using a closed loop, with the load rejected to a cooling tower. Various pressure, temperature, relative humidity and flow measurements were recorded using a labview data acquisition system. Combustion data, such as %CO2, %CO and flue gas temperature were recorded using a separate, dedicated computer. A rack was constructed for mounting boiler supply and return lines, along with instrumentation in a modular assembly that can be easy removed and

http://www.etcc-ca.com/images/boiler_research_project_-_ats-te_final_report_pcb_05092012.pdf

http://www.etcc-ca.com/images/boiler_research_project_-_ats-te_final_report_pcb_05092012.pdf


installed for future use. Flexibile lines connect this modular rack assembly to the boiler, allowing for ease of swapping new test units in and out.

Several design modifications were made to the existing boiler test apparatus in place from Phase I Std. 155P development efforts.

· Relocate boiler into an environmental chamber, where ambient conditions can be maintained during testing

· Shorten run of pipe between boiler and cooling tower, reducing the amount of time needed to stabilize system operating conditions

· Purchase more accurate temperature and gas volumetric flow instrumentation

· Place several redundant temperature sensors in boiler inlet and outlet water for comparison

· Modularize test apparatus for ease of swapping boilers

FIGURE 2. MODULAR RACK ASSEMBLY WITH INSTRUMENTATION UNDER CONSTRUCTION INSIDE ENVIRONMENTAL CHAMBER


FIGURE 3. FLEX LINE FOR EASE OF INSTALLATION AND REMOVAL OF INDIVIDUAL TEST UNITS

FIGURE 4. INSULATED MODULAR RACK ASSEMBLY WITH INSTRUMENTATION UNDER CONSTRUCTION INSIDE ENVIRONMENTAL CHAMBER


The gas and water piping configuration is shown schematically in Figure 5 and Figure 6. A recirculation pump was included at the boiler with idea of running higher ΔT at the flow meter than at the boiler. But the recirc loop was not used during testing for two reasons: (1) it failed, and (2) the water meter was less accurate than the water temperature sensors, particularly at low flow, so running high ΔT and low flow at the meter was less accurate than not using the recirc pump. The boiler outlet piping also includes three different flow paths before the Tout temperature sensors and the mixing verification array. One path includes a mixing pump to eliminate stratification and one include a short section of smaller diameter pipe to test that as a mixing device. Unfortunately no stratification testing was performed in this Phase of testing due to time/budget constraints and because it was difficult to generate much stratification given the limited boiler turndown and long flex hose at the boiler outlet.


FIGURE 5. SCHEMATIC OF TEST APPARATUS

FIGURE 6. SCHEMATIC OF BOILER LOAD REJECTION/TIE IN WITH CORIOLIS FLOW LOOP

DIFFICULTY TUNING UNIT 2 In order to keep Unit 2 within the required CO2 range it was necessary to retune the boiler between some of the tests. For example, from Test 2.03 to 2.04 the room temperature was raised from approximately 65oF to 85oF and the firing rate was changed from Hi to Lo. This caused a rise in CO2, and the boiler needed to be retuned by turning the set screw 1/4 turn Counter clockwise.

Another issue encounted with Unit 2 was harmonics in the flue at low fire (it made a tremendously load trumpeting noise also created significant vibrations). To eliminate the harmonics and achieve stability it was necessary to raise the minimum fire test from the boilers minimum of 20% to approximately 30%. It is interesting to note that this problem did not occur in Phase I so presumably the issue is related to the modified flue configuration in Phase II.

TEST PLAN

The two boilers tested in this Phase are listed in Table 2.

TABLE 2. SUMMARY OF TEST UNITS

Unit # Type Make/Model Input Turndown


(Btu/h)

1

Outdoor, atmospheric copper fin

tube

Laars PW 715

715,000 single stage

2 Condensing,

cast iron Hydrotherm

KN-6 600,000 5:1

A series of steady state tests and a couple of idling tests were run on each boiler. These tests are listed in Table 3. Boilers were be tested at hi and lo firing rate, hi (180/140) and low (120/80) water temperatures, various room temperatures (Troom), various room air change rates (ACH), and other test conditions as described below. Jacket Loss measurements were only taken during some of the steady state tests, as indicated in the table.

TABLE 3. SUMMARY OF TESTS

Test ID Unit Fire

Rate HWT Troom ACH Jacket

Loss? Comments

2.01.00 2 Hi Hi Hi 85 <2 Y CO2 was not within required tolerance 2.01.01 2 Hi Hi Hi 85 <2 Y CO2 was within required tolerance 2.02 2 Lo Hi Lo 65 >10 Y Expecting to see hi jacket losses. Low fire at 30% fire. 2.03 2 Hi Lo Lo 65 >10 Expecting to see relatively low efficiency 2.04 2 Lo Lo Hi 85 <2 Expecting to see relatively high efficiency 2.05 2 Lo Lo Hi 85 <2 Throttle valve between Tin2 and Tin3 to create as high a

ΔP as the circ pump can handle. Lab view includes pressure drop. Expecting to see higher thermal efficiency than 2.04 due to friction heat at throttled valve.

2.06 2 Lo Lo Lo 65 >10 Expecting to see relatively low efficiency compared to 2.04 2.07 2 Auto Hi Lo 65 >10 Idling Test - supposed to be 10F differential but ended up

at 4F 2.08 2 Auto Hi Lo 65 >10 Idling Test – 4F differential, 2 minute delay on boiler

controller 2.09 2 Auto Hi Lo 65 >10 Idling Test – 4F Differential, using the default 10 sec boiler

controller delay (it made no difference in boiler control) 1.01 1 Hi Hi Lo 65 >20 Y Expecting relatively high jacket losses. Flue gas temp was

not stable. 1.02 1 Hi Hi Hi 95 <2 Y Expecting relatively low jacket losses. Flue gas temp was

not stable. 1.03 1 Auto Hi Lo 65 >10 Idling Test – 10F Differential 1.04 1 Auto Hi Lo 65 >10 Idling Test – 4F Differential 1.05 1 Hi Hi Lo 65 >20 Y With side panels off with jacket loss of inner panels.

INSTRUMENTATION PLAN

STEADY STATE THERMAL EFFICIENCY TEST PARAMETERS The following parameters are measured during a steady state test in order to calculate boiler thermal efficiency.

· Water Volumetric Flow Rate (gpm)


· Water Density (lb/ft3)

· Water Supply Temperature (F)

· Water Return Temperature (F)

· Non-Compensated Natural Gas Volumetric Flow Rate (ft3/hr)

· Natural Gas Volumetric Flow Compensation Temperature (F)

· Natural Gas Higher Heating Value (BTU/ft3)

· Natural Gas Volumetric Flow Compensation Pressure (inches H2O)

· Barometric Pressure (psia)

· Auxiliary Power Input (kW)

STEADY STATE COMBUSTION EFFICIENCY TEST PARAMETERS

The following parameters must be determined in order to determine boiler combustion efficiency. Many of these parameters are also required for determining boiler thermal efficiency, and thus have already been discussed.

· Non-Compensated Natural Gas Volumetric Flow Rate (ft3/hr.)





· Flue Gas Temperature (F)

· Burner Inlet Temperature (F)

· CO2 Concentration (%)

· Relative Humidity (%)

· Boiler Condensate Flow Rate (lb/hr)

· Flue Condensate Flow Rate (lb/hr)

ESTABLISHING UNCERTAINTY IN MEASUREMENT OF TEST PARAMETERS

A detailed uncertainty analysis has been performed on each of the measurement parameters used to establish boiler thermal and combustion efficiency. Some sources of error are unique to each test measurement parameter, and will be discussed in individual sections. Other sources of error, such as repeatability of pre test vs. post test calibrations and error due to fluctuating test data are accounted for in the same manner for all temperature, pressure and water flow parameters.


REPEATABILITY OF CALIBRATIONS (PRE VS. POST TEST CALIBRATION)

Some drift in measurement may occur during the course of testing between pre and post calibrations. In order to account for the impact of this drift on the overall uncertainty, precision and bias errors are quantified.

Equation 1. Calculation of precision error resulting from repeatability in calibration of instrumentation.

Repeatability of Calibrations (Precision Error) = å nPtsCalibratio

SEE

Where:

SEE - Standard Error of Estimate of a correction curve fit to the calibration data

CalibrationPts – Number of calibration points performed on instrumentation

Equation 2. Calculation of fossilized bias error resulting from repeatability in calibration of instrumentation.

Repeatability of Calibrations (Fossilized Error) =

( )2

2

* CalBiastnPtsCalibratio

SEE+

÷÷÷

ø

ö

ççç

è

æ

å

Where:

SEE - Standard Error of Estimate

CalibrationPts – (Summed) calibration points performed on instrumentation

t – Student t degrees of freedom in pre and post test calibration data

CalBias – Bias error introduced during the process of calibration. For this testing effort, this is only accounted for in temperature non-uniformity of the calibration block used for instrument calibration.

ERROR DUE TO FLUCTUATING TEST DATA

Uncertainty is introduced to the measured parameter by fluctuation of data between one measurement and the next. The impact of these precision errors from one measurement to the next on the total uncertainty is reduced by taking more data points. All temperature, pressure and flow measurements during the two hour long steady state test were taken on two second intervals. All power measurements were taken on fifteen second intervals. CO2 measurements from the combustion analyzer were taken on one second intervals.

Equation 3. Calculation of precision error resulting test data fluctuations.

Error Due to Fluctuating Test Data (Precision Error) = å DataPts

s


Where:

σ - Standard deviation in test data

DataPts – (Summed) test data measurements

Equation 4. Boiler Thermal Efficiency Calculation

( )( ) ( )aux

barometricgas

gasgasgas

returnplywaterfeedwaterfeedwater

thermal

kWpp

TVHHV

TTcpV

*341373.14

036.**

46046060**

**4805.760** sup

+úúû

ù

êêë

é +

++

-=

&

& rh

Where:

feedwaterV& = Volumetric flow rate of boiler water (gpm)

feedwaterr = Density of boiler water (lb./cf) cpwater = Water specific heat capacity (btu/lbm)

plyTsup = Boiler water supply temperature (F)

returnT = Boiler water outlet temperature (F)

gasHHV = Natural gas higher heating value (BTU/cf)

gasV& = Non-compensated volumetric flow rate of natural gas (cf/h)

gasT = Natural gas temperature (F)

gasp = Natural gas gage pressure (inches H2O)

barometricp = Barometric Pressure (psia)

auxkW = Auxialiary power introduced to the test though (kW)

WATER VOLUMETRIC FLOW RATE

DESCRIPTION OF MEASURED PARAMETER

Volumetric flow rate (gpm) measurements are performed using a 2.5” diameter M2000 Magnetic Flow Meter manufactured by Badger Meter. Magnetic flow meters produce a volumetric flow reading through measurement of the average velocity of the passing fluid with a known inner diameter. An analog output sent from the meter is sent to the labview data acquisition system for logging flow data.

RESOLUTION AND ACCURACY CONSIDERATIONS

TABLE 4. STD. 155P WATER VOLUMETRIC FLOW REQUIREMENTS


Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy

Example of Instrument

Type Range

Specified

Flow Water or Feedwater

0.25% of hourly rate

± 0.25% of hourly rate Flow Meter As

Needed

ASHRAE Standard 155P requires a minimum resolution and accuracy of 0.25% of hourly rate (percent of reading) for boiler water volumetric flow rate measurements. The Badger Meter used meets the minimum resolution requirements of the standard, which correspond to requiring hundredths of a gpm volumetric flow precision at 5 gpm, the lowest flow rate that may be encountered during a test. Manufacturer’s literature states the meter has an accuracy of +/- 0.25%, but does not indicate whether or not this is percent of full scale or percent of reading. See the appendices for more details. A similar full bore electromagnetic from Onicon (F-3200) lists accuracy as follows:

A calibration was performed on the flow meter by a NIST traceable flow standard to correct for any drift in the meters factory calibration.

APPLICATION OF SELECTED INSTRUMENTATION

This meter was installed at least 20 diameters downstream and 10 diameters upstream any fittings, valves or other devices that might create a flow disturbance impacting the volumetric flow measurement. The flow meter is placed downstream of the cooling tower and upstream of the electric resistance water heater, main loop recirculation pump and boiler return.


FIGURE 7. BADGER M2000 MAGNETIC FLOW METER

INSTRUMENT CALIBRATION AND DATA PROCESSING Calibration of this electromagnetic flow meter was performed by placing it in series with a NIST traceable ½”, 1” and 2” coriolis flow meter standards. Calibration certificates for these meters are available in the appendix. Using a recirculation pump, water flows through both meters while in series for comparison of the readings. An average raw reading from the analog output of the electromagnetic flow meter was first taken at 0 gpm and 70 gpm for a period of five minutes and compared against the reading of the coriolis standard. The comparison of these readings is used to create a two point calibration programmed into labview of the electromagnetic flow meter. Once this two point calibration offset is applied to the raw data, a pre and post calibration verification was performed at various flow rates between 0 and 70 gpm. Further post processing of this two-point calibration is possible using pre and post calibration verification data as a means of accounting for any hysteresis in the initial two-point calibration.

QUANTIFICATION OF UNCERTAINTY IN MEASURED PARAMETER

The following error sources were accounted for in the establishment of the total uncertainty in boiler water volumetric flow rate.

TABLE 5. IDENTIFYING SOURCES OF ERROR IN WATER VOLUMETRIC FLOW RATE

Error Sources Bias Precision 1. Error in calibration of flow standard B1 2. Repeatability of calibrations (pre vs. post test cal) F2 S2


3. Error due to fluctuating test data S3 Bias Error (B1) in the coriolis flow standard used to calibrate the boiler magnetic flow meter is 0.3% of hourly rate throughout its range. A calculation of this uncertainty is provided in the appendix. In order to maintain this uncertainty in the calibration standard used, different diameter coriolis meters were used for different flow rates. This value is obtained by root sum squaring all of the uncertainties into its calibration, including some room in case the coriolis meter drifts over time. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty of 95% confidence.

TABLE 6. RESULTING UNCERTAINTY IN WATER VOLUMETRIC FLOW RATE

Test Measurement Source

Actual Uncertainty in

Test Parameter

Required Uncertainty in

Test Parameter

Meets ASHRAE Std

155 Requirement?

Water Volumetric Flow (% hourly rate) 0.302% 0.250% No

WATER DENSITY


In order to convert water volumetric flow rate (gpm) into mass flow rate (lbm/hr.), density of the passing fluid must be determined. Water density is a function of both temperature and pressure, but is much more sensitive to change in temperature than pressure. Using Engineering Equations Solver, a software analysis tool including the physical properties of various substances, water density was calculated as a function of temperature with pressure held constant at 15 psig.


No mention of water density is made in the accuracy requirements of ASHRAE Std 155P. Due to the non-linearity of water density across the return water temperatures encountered during testing, two separate functions were created for Hi (140F) and Lo (80F) return water conditions. This approach ensures accuracy of the density correction approach depending on which test is being performed, hi or low supply temperature.


Boiler supply temperature 3 is passed to the function developed to calculate the density of the fluid passing through the water flow meter. Boiler supply temperature 3 was chosen because it is closest to the water flow meter.



TABLE 7. IDENTIFYING SOURCES OF ERROR IN WATER DENSITY

Error Sources Bias Precision 1. Error due to lack of significant digits B1

An uncertainty of .01 lbm/cf is assumed in the physical properties taken from Engineering Equation Solver due to a lack of significant digits, as the density outputs from Engineering Equation Solver are limited to resolution in the hundredths. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty at 95% confidence.

TABLE 8. RESULTING UNCERTAINTY IN WATER DENSITY



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

Water Density (lb./cf) 0.010 n/a n/a

TEMPERATURE MEASUREMENT


Highly accurate and stable type A precision RTD’s were selected for taking water supply and return measurements, including return mixing verification, used in the calculation of boiler thermal efficiency. Type T thermocouple probes were used for measuring natural gas temperature, supply mixing verification, burner inlet air temperature and environmental chamber ambient temperature. Type T thermocouples were used for all jacket and flue temperature measurements. All temperature sensors were selected and calibrated with the intention of meeting the requirements of ASHRAE Std 155P.

TABLE 9. STD. 155P WATER TEMPERATURE INSTRUMENTATION REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy

Example of Instrument Type

Range Specified

Temperature

Air 1 °F ± 1 °F Thermometer or Thermocouple

65 to 100 °F

Water 0.2 °F ± 0.2 °F1

Thermometer or Thermocouple

80 to 190 °F

Flue Gas 2 °F ± 2 °F Thermocouple Grid

350 to 650 °F


INSTRUMENT CALIBRATION AND DATA PROCESSING

Temperature sensor calibration was performed on each temperature sensor using an ice bath and constant temperature block with a NIST traceable temperature standard.

Temperature Instrumentation Calibration Process

1. Place temperature instrumentation and temperature standard in the same ice bath. Wait several minutes for the temperature reading on the temperature standard digital display to level off.

2. Record the raw low temperature reading from each temperature probe, along with the temperature reading from the temperature standard display.

3. Place temperature instrumentation and temperature standard in the same hot block. Wait several minutes for the temperature reading on the temperature standard digital display to level off.

4. Record the raw high temperature reading from each temperature probe, along with the temperature reading from the temperature standard display.

5. Program raw low and high temperature reading from instrumentation along with low and high calibration standard temperature reading into labview, generating a two-point calibration offset correcting the raw data to the temperature standard.

6. With the calibration offset applied, perform calibration verification measurements at various temperatures within the range seen during testing. This will be performed both before testing (pre-calibration verification) and after testing has completed (post-calibration verification).

Temperature calibration was performed at 32F (ice bath) and 190F (HART 9105 Hot Block) for all temperature instrumentation excluding flue gas temperature instrumentation. Flue gas temperature sensor calibration was performed at 32F (ice bath) and 250F (KAYE HTR-600 Hot Block), covering all temperatures encountered during testing. Further post processing of this two-point temperature calibration is possible using pre and post calibration verification data as a means of accounting for any inaccuracies of the initial two-point calibration. Data post processing will be discussed in detail in the uncertainty analysis section of this report.


FIGURE 8. HART 9105 HOT BLOCK WITH TEMPERATURE STANDARD PROBE AND TEST INSTRUMENTATION INSERTED

FIGURE 9. KAYE HTR-600 HOT BLOCK WITH TEMPERATURE STANDARD PROBE AND TEST INSTRUMENTATION INSERTED


FIGURE 10. FLUKE TEMPERATURE REFERENCE STANDARD (PG&E #30032)


TABLE 10. IDENTIFYING SOURCES OF ERROR IN TEMPERATURE INSTRUMENTATION

Error Sources Bias Precision 1. Error in calibration of temperature standard B1 2. Error due to spatial temperature variation B2 3. Error due to calibration block non-uniformity B3 4. Repeatability of calibrations (pre vs. post test cal) F4 S4 5. Error due to fluctuating test data S5

Bias Error (B1) in the temperature standard used to calibrate all sensors was conservatively estimated at 0.1F. A placeholder has been created for concerns regarding the bias limit due to spatial variation (B2) where the location of the temperature measurement can have an impact on the intended temperature measurement. For example, natural gas enters the environmental chamber in an non insulated pipe where temperature compensation measurements are made near the natural gas volumetric flow meters. Gas temperature can increase 10oF from the first and last natural gas temperature measurement. Temperature compensation for the natural gas volumetric flow meters may have an impact on the final natural gas volumetric flow rate depending on where they are taken. Due to the difficulty in actually determining the uncertainty, no value for spatial uncertainty has been assumed. Some non-uniformity exists within the calibration block, where both the temperature standard and test instrumentation are placed together for comparison. Bias error due to the uncertainty in the temperature uniformity of the calibration block (B3) is calculated to be 0.025 oF by root sum squaring all sources of uncertainty in non-uniformity (radial, axial etc.) provided by a hot block


manufacturer. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty at 95% confidence.

TABLE 11. RESULTING UNCERTAINTY IN TEMPERATURE MEASUREMENT



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

Supply Water Temperature 1 (°F) 0.168 0.200 Yes Supply Water Temperature 2 (°F) 0.113 0.200 Yes Supply Water Temperature 3 (°F) 0.106 0.200 Yes Return Water Temperature 1 (°F) 0.106 0.200 Yes Return Water Temperature 2 (°F) 0.113 0.200 Yes Natural Gas Temperature - 1500 CFH Meter (°F) 0.130 1.000 Yes Natural Gas Temperature - 800 CFH Meter (°F) 0.114 1.000 Yes Ambient Temperature (°F) 0.223 1.000 Yes Burner Inlet Temperature (°F) 0.160 1.000 Yes Flue Gas Temperature - TC Grid (°F) 0.316 / 41* 2.000 Yes/No

*Note: Flue gas temperatures for Unit 1 were recorded using the combustion analyzer probe, which is reported by the manufacturer to have a 41 oF uncertainty.

BOILER WATER INLET TEMPERATURE


Boiler water inlet temperature measurement is a required variable in the calculation of the amount of energy the boiler put into the passing water.


Tinlet@Boiler – 1/8” diameter type T thermocouple probe inserted normally into boiler water flow surrounded by an non insulated pipe.

Tinlet1 - 1/8” diameter type A precision platinum RTD inserted into the flow stream at an elbow with the flow direction along with (4) 1/8” diameter type T thermocouple probes at 12:00, 3:00, 6:00 and 9:00 2/3 of the way from the center of the pipe to the inner wall, inserted into the flow stream at an elbow with the flow direction surrounding the center RTD.


FIGURE 11. BOILER INLET TEMPERATURE 1 MEASUREMENT ARRAY (RTD CENTER, THERMOCOUPLES SURROUNDING)

Tinlet2 - 1/8” diameter type A precision platinum RTD inserted normally into center of boiler water flow stream within an insulated pipe.

FIGURE 12. BOILER INLET TEMPERATURE 2 MEASUREMENT


Tinlet3 - 1/8” diameter type A precision platinum RTD inserted in elbow facing into the center of boiler water flow stream.

FIGURE 13. BOILER INLET TEMPERATURE 3 MEASUREMENT

BOILER WATER OUTLET TEMPERATURE


Boiler water outlet temperature measurement is a required variable in the calculation of the amount of energy the boiler put into the passing water.

APPLICATION OF SELECTED INSTRUMENTATION Return water temperature measurement is performed by calibrated sensors in three separate locations within the boiler loop in the locations/orientations described below: Toutlet@Boiler – 1/8” diameter type T thermocouple probe inserted normally into boiler water flow surrounded by an non insulated pipe. Toutlet1 - 1/8” diameter type A precision platinum RTD probes inserted into the flow stream at an elbow with the flow direction along with (4) 1/8” diameter type A precision platinum RTD probes at 12:00, 3:00, 6:00 and 9:00 2/3 of the way from the center of the pipe to the inner wall, inserted into the flow stream at an elbow with the flow direction surrounding the center RTD.


FIGURE 14. BOILER OUTLET TEMPERATURE 1 (ALL RTD’S)

Toutlet2 - 1/8” diameter type A precision platinum RTD probe inserted in elbow facing into the center of boiler water flow stream.


FIGURE 15. BOILER OUTLET TEMPERATURE 2

NATURAL GAS VOLUMETRIC FLOW COMPENSATION TEMPERATURE


Natural gas volumetric flow must be converted from actual to standard conditions in order to properly calculate boiler energy input, as the Higher Heating Value of natural gas is reported under standard conditions. A temperature measurement at the gas meter is necessary to perform the conversion from actual to standard cubic feet per hour gas volumetric flow.

APPLICATION OF SELECTED INSTRUMENTATION Natural gas temperature measurement required for compensation of natural gas flow rate is measured in three locations described below: Tgas1500 – Temperature of natural gas flowing through the 1500CFH capacity natural gas volumetric flow meter measured with an 1/8” diameter type T thermocouple probe inserted normally into natural gas flow within 4 inches upstream of the gas meter. Tgas800 – Temperature of natural gas flowing through the 800CFH capacity natural gas volumetric flow meter measured with an 1/8” diameter type T thermocouple probe inserted normally into natural gas flow within 4 inches downstream of the gas meter.

PRESSURE MEASUREMENT


ASHRAE Std. 155P requires that natural gas compensation pressure resolution and accuracy be +/- 0.1” respectively. Rosemount pressure transmitters spanned to as low of a range possible were selected to perform these pressure measurements.

TABLE 12. STD. 155P PRESSURE INSTRUMENTATION REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy


Type Range

Specified

Pressure

Atmospheric 0.05" hg ±0.05" hg Barometer 28 to

31" hg

Steam 0.1" hg ± 0.2" hg

Mercury Manometer

0 to 5" hg

Fuel Oil 5 psi ± 5 psi Bourdon Tube Gage

80 to 250 psi


Firebox

0.01" water

±0.01" water Draft Gage

0 to 0.5" water

(natural draft)

0.02" water


0 to +2.5" water

(forced draft)

Vent 0.01" water


0 to 0.15" water

Flue 0.01" water

±0.01" water Draft Gage 0 to 0.5"

water

Gas 0.1" water

±0.1" water Manometer 0 to 10"

water


Calibration of the gage and pressure transmitters was performed with a NIST traceable dead weight tester standard. Calibration of the differential pressure transmitters was performed with a micro manometer. During the pressure transmitter calibration process, a very accurately defined pressure is applied to the pressure transmitter at both the low and high ranges of operation. The analog output from the transmitter is then converted to a corrected pressure reading in labview by applying a two point calibrations. Once the two point calibration correction has been applied, a pre test calibration verification is performed at several points within the range of operation to determine whether or not the calibration was properly applied. Pre and post test calibration verification data is used to post process the data and further improve its accuracy.

Pressure Transmitter Calibration Process

1. Open pressure transmitter to atmosphere.

2. Record raw voltage output at atmospheric pressure.

3. Using a pressure calibration standard (PDWT006), apply a known pressure to the pressure transmitter (in reference to atmospheric pressure).

4. Record the raw voltage from the pressure transmitter, along with pressure applied by the pressure standard.

5. Program raw low (0 gage) and high voltage readings from the pressure transmitter along with low and high calibration standard pressure reading into labview, generating a two-point calibration offset correcting the raw data to the pressure standard.

With the calibration offset applied, perform calibration verification measurements at various pressures within the range seen during testing. This will be performed both before testing (pre-calibration verification) and after testing has completed (post-calibration verification).


FIGURE 16. AMETEK PKII DEAD WEIGHT TESTER (PRESSURE CALIBRATION STANDARD)


FIGURE 17. CALIBRATION OF ROSEMOUNT PRESSURE TRANSMITTER USING DEAD WEIGHT TESTER

NATURAL GAS VOLUMETRIC FLOW COMPENSATION PRESSURE


Natural gas volumetric flow must be converted from actual to standard conditions in order to properly calculate boiler energy input, as the Higher Heating Value of natural gas is reported under standard conditions. A pressure measurement at the gas meter is necessary to perform the conversion from actual to standard cubic feet per hour gas volumetric flow. This natural gas pressure measurement at each meter is summed with barometric pressure to calculate the final pressure conversion factor.


Natural gas pressure readings are taken with Rosemount static and differential pressure transmitters. Three total pressure readings were recorded during each test. A gage pressure reading is taken in the natural gas line just upstream the larger, 1500 CFH capacity volumetric flow meter, a differential pressure is taken across the 1500 CFH capacity natural gas flow meter and a static pressure is taken just downstream of the 800 CFH capacity volumetric flow meter. In order to compensate the actual cubic feet per hour natural gas volumetric flow rate reading to standard cubic feet, an upstream gas pressure is needed. Pressure compensation of the 1500 CFH capacity meter is performed with the static pressure reading taken upstream of


the meter. Pressure compensation of the 800 CFH meter located downstream of the 1500 CFH meter is performed by taking the difference between the gage pressure upstream and the differential pressure across the 1500 CFH meter. Each pressure transmitter was spanned to a range that is close to the range anticipated during testing.



TABLE 13. IDENTIFYING SOURCES OF ERROR IN GAS PRESSURE INSTRUMENTATION

Error Sources Bias Precision 1. Error in calibration of pressure standard B1 2. Repeatability of calibrations (pre vs. post test cal) F2 S2 3. Error due to fluctuating test data S3

Error in the dead weight tester calibration standard (B1) is .025% of reading. See the appendix for the calibration standard. Error in the micro manometer is 2% of reading. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty at 95% confidence.


TABLE 14. RESULTING UNCERTAINTY IN GAS PRESSURE INSTRUMENTATION



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

1500CFH Pressure Compensation (inches H2O) 0.024 0.100 Yes 800CFH Pressure Compensation (inches H2O) 0.024 0.100 Yes

BAROMETRIC PRESSURE


Barometric pressure is summed with natural gas pressure at each natural gas volumetric flow meter to calculate a pressure compensation factor. The pressure compensation factor is used in the conversion from actual to standard cubic feet per hour volumetric natural gas flow rate.


A rooftop mounted weather station was used to perform barometric (atmospheric) pressure measurements. The output of this weather station is wired into the network, and accessed using labview when tests are running.


Calibration of this instrument was performed through a comparison of its reading with an accurate pressure standard maintained at PG&E’s calibration lab. This comparison was performed on 12/11/12, where the calibration lab reported a barometric pressure of 14.50 psia, with the weather station reporting 14.49 psia.


TABLE 15. IDENTIFYING SOURCES OF ERROR IN BAROMETRIC PRESSURE

Error Sources Bias Precision 1. Error in calibration of pressure standard B1 2. Repeatability of calibrations (pre vs. post test cal) F2 S2 3. Error due to fluctuating test data S3

Error in the calibration standard lab pressure reading (B1) is estimated to be .02 psia. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty at 95% confidence.


TABLE 16. RESULTING UNCERTAINTY IN BAROMETRIC PRESSURE INSTRUMETATION



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

Barometric Pressure (psia) 0.020 0.025 Yes

NON-COMPENSATED NATURAL GAS VOLUMETRIC FLOW RATE


Boiler energy input comes primarily from the energy content in natural gas supplied to the boiler. In order to determine boiler thermal and combustion efficiency, a measurement must be made of the quantity of this energy content being consumed by the boiler.

RESOLUTION AND ACCURACY CONSIDERATIONS ASHRAE Std. 155P requires resolution of 0.25% and an accuracy of +/- 0.25% of hourly rate (indication) for non-compensated natural gas volumetric flow. Two positive displacement rotary gas meters with a pulse output feature were selected as the best option at a reasonable cost. These dresser roots meters offer thousandths of cubic foot gas volume resolution with an accuracy of 0.35% of hourly rate at a cost of about $2000 each.

TABLE 17. STD. 155P NATURAL GAS VOLUMETRIC FLOW MEASUREMENT REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy


Type Range

Specified

Volumetric Flow

Gas 0.25% of

hourly rate

± 0.25% of hourly

rate Volume Meter As

Needed

There are limitations in the turndown accuracy of these meters, as indicated in the figure below. To account for this potential concern, an 800CFH and 1500CFH meter were selected to attempt to keep each boiler being tested above at least 10% of the smallest meters rating, while allowing a boiler as large as 1.5 million Btuh to be tested. The lowest gas volumetric flow rate that can be managed with reasonable accuracy in this setup is 80CFH, approximately 80,000 btuh. This level of gas consumption was not anticipated to be approached during the course of this phase of testing.


FIGURE 19. CALIBRATION CURVE OF NATURAL GAS VOLUMETRIC FLOW METER


Natural gas volumetric flow rate fed to the boiler was measured in series by two Dresser positive displacement rotary meters. A 1500CFH capacity model 15C175 meter is installed upstream of a 800CFH capacity model 8C175 meter with the option to bypass the 800CFH meter while testing larger boilers. An feature added to each of these meters is the ability to send a pulse per fixed increment of volume (0.0025 acf/pulse for the 1500CFH meter and 0.00185175 acf/pulse for the 800 CFH meter). labview uses pulse edge detection to capture and record the total number of pulses from each meter simultaneously during a test.


FIGURE 20. 1500 CUBIC FOOT PER HOUR CAPACITY NATURAL GAS VIOLUMETRIC FLOW METER

FIGURE 21. 800 CUBIC FOOT PER HOUR CAPACITY NATURAL GAS VIOLUMETRIC FLOW METER


FIGURE 22. BOTH NATURAL GAS VOLUMETRIC FLOW METERS WITH 800 CFH METER BYPASS LOOP

INSTRUMENT CALIBRATION AND DATA PROCESSING Both natural gas volumetric flow meters underwent a 10 point factory calibration across their range. The calibration curve generated at the factory is used to post process the raw data collected using labview, lowering the overall uncertainty in the reading. The post processing technique is that same as described previously.


TABLE 18. IDENTIFYING SOURCES OF ERROR IN NATURAL GAS VOLUMETRIC FLOW RATE

Error Sources Bias Precision 1. Error in calibration of flow standard B1 2. Repeatability of calibrations (pre vs. post test cal) F2 S2

Bias error in the factory calibration was provided by the vendor of the meter, totaling approximately 0.3% of the hourly rate of the meter at each calibration point. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty of 95% confidence.

TABLE 19. RESULTING UNCERTAINTY IN NATURAL GAS VOLUME METER


Actual Uncertainty

in Test Parameter

Required Uncertainty

in Test Parameter

Meets ASHRAE Std

155 Requirement?

1500 CFH Capacity Meter Non-Compensated Gas Volumetric Flow (% hourly rate) 0.334% 0.250% No 800 CFH Capacity Meter Non-Compensated Gas Volumetric Flow (% hourly rate) 0.305% 0.250% No


NATURAL GAS HIGHER HEATING VALUE


Higher heating value is a measure of the total energy content of natural gas on a per unit volume basis at standard conditions. Weekly readings of natural gas higher heating value (HHV) are made available to the public at the following website: http://www.pge.com/pipeline/operations/therms/heat_value.shtml. These weekly reported values are used to establish HHV of the gas supplied to the boiler during testing. Location J11 is used to represent the energy content of natural gas in our area of the natural gas distribution network. More information about how PG&E collects gas samples is located at the following link: http://www.pge.com/pipeline/library/faqs/therms_faq.shtml#0.


ASHRAE Std. 155P requires that the accuracy in natural gas higher heating value be 1% or less. Due to time constraints, no cross checks of weekly reported values were able to be performed.

TABLE 20. STD. 155P NATURAL GAS ENERGY CONTENT MEASUREMENT REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy


Type Range

Specified

Calorific value

Heat content of

natural gas

2 Btu/ft3 ± 1% of reading

Calorimeter or gas

chromatography

970-1100 Btu/ft3

(natural gas)

TABLE 21. ANALYZING STANDARD DEVIATION IN WEEKLY HHV VALUES

Date Sampled

Gas HHV

(BTU/cf) 12/10/2012 1,027 12/3/2012 1,024 11/26/2012 1,027 11/19/2012 1,024 11/12/2012 1,024 11/5/2012 1,023 10/29/2012 1,022

Std Dev. (BTU/cf) 1.76

http://www.pge.com/pipeline/operations/therms/heat_value.shtml

http://www.pge.com/pipeline/library/faqs/therms_faq.shtml#0



No instrumentation was required in the lab to take any higher heating value readings, as online reported values are measured in the field. A calorimeter or gas chromatograph can be purchased and installed to perform these measurements if desired.

QUANTIFICATION OF UNCERTAINTY IN MEASURED PARAMETER After consulting with the PG&E technicians responsible for collecting the data, an assumption was made that the uncertainty in the measurement of natural gas heating value by the utility on a weekly basis has an uncertainty within 1%, or roughly 10 BTU’s/scf. On a week by week basis between 10/29/12 and 12/10/12, the energy content of natural gas reported by the utility has a standard deviation of 1.76 BTU/scf, reinforcing that assumption may be reasonable. Without a more frequent sampling period, it is difficult to know what the actual uncertainty in the measurement of natural gas energy content is. More information on the uncertainty in HHV is also available in the Phase I report.

BOILER AUXILIARY POWER INPUT


Boiler power input includes all electric consumption of the boiler or pump within the control volume being tested. The control volume boundary is defined by return temperature measurement 2 and supply temperature measurement 3. This energy transfer is assumed to increase the output of the boiler, and must be accounted for to properly calculate thermal efficiency. The main system pump is not inside the control volume boundary and thus its power is not included. The recirculation pump pump did not run during any testing. Thus the only real auxiliary power is the boiler combustion fan and the mixing pumps (discussed in next section).


ASHRAE Std. 155P requires a 1% accuracy of energy consumption measurements. DENT instruments reports a 1% accuracy of their instruments, which were used for logging boiler kW.

TABLE 22. STD. 155P BOILER AUXILIARY POWER MEASUREMENT REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy

Electrical power Watts ± 1% of

reading




TABLE 23. IDENTIFYING SOURCES OF ERROR IN BOILER AUXILIARY POWER MEASUREMENT

Error Sources Bias Precision 1. Error in calibration of kW Logger B1 2. Error due to fluctuating test data S2

A bias error of 1% is assumed citing the factory calibration of the DENT meter used for power monitoring. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty of 95% confidence.

TABLE 24. RESULTING UNCERTAINTY IN BOILER AUXILIARY POWER INPUT



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

Boiler Power Consumption (% of kW reading) 1.42% 1% No


MIXING PUMP AUXILIARY POWER INPUT


A mixing pump was installed to mitigate stratification in the boiler water outlet temperature senor array. Mixing pump power input includes all electric consumption of the boiler or pump within the control volume being tested. The control volume boundary is defined by return temperature measurement 2 and supply temperature measurement 3. This energy transfer is assumed to increase the output of the boiler, and must be accounted for to properly calculate thermal efficiency. The main system pump is not inside the control volume boundary and thus its power is not included. The mixing pump ran continuously during all steady state testing.


ASHRAE Std. 155P requires a 1% accuracy of energy consumption measurements. DENT instruments reports a 1% accuracy of their instruments, which were used for logging boiler kW.

TABLE 25. STD. 155P MIXING PUMP AUXILIARY POWER MEASUREMENT REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy

Electrical power Watts ± 1% of

reading


TABLE 26. IDENTIFYING SOURCES OF ERROR IN MIXING PUMP AUXILIARY POWER MEASUREMENT

Error Sources Bias Precision 1. Error in calibration of kW Logger B1 2. Error due to fluctuating test data S2

A bias error of 1% is assumed citing the factory calibration of the DENT meter used for power monitoring. Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty of 95% confidence.

TABLE 27. RESULTING UNCERTAINTY IN MIXING PUMP AUXILIARY POWER INPUT



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

Mixing Pump Consumption (% of kW reading) 1.53% 1.00% No


STEADY STATE COMBUSTION EFFICIENCY TEST PARAMETERS The following parameters must be determined in order to determine boiler combustion efficiency. Many of these parameters are also required for determining boiler thermal efficiency, and thus have already been discussed.

· Non-Compensated Natural Gas Volumetric Flow Rate (ft3/hr.)





· Flue Gas Temperature (F)

· Burner Inlet Temperature (F)

· CO2 Concentration (%)

· Relative Humidity (%)

Equation 5. Boiler steady state combustion efficiency

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LGL +--=h

Equation 6. Flue Losses, Lf

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ø

öççè

æ -+÷÷

ø

öççè

æ+÷

øö

çèæ -

= frf

rrf TT

TTLNTT

COCOU

APAhPTC *1194*3^10*5.7*86.19**1***0017.

10 2

24

Where:

A

P

T

U

hfg

mcond,ss

qin, cond,ss

Tflue,ss – Flue Temperature (f)

Tair – Boiler Inlet Air Temperature (F)

Tf – Flue Temperature (deg R)

Tr – Boiler Inlet Air Temperature (deg R)

BURNER INLET TEMPERATURE


Burner inlet air temperature is used to fix the conditions of the boiler inlet air when calculating its combustion efficiency.


A thermocouple probe was mounted at the inlet for unit #2 and near the inlet for unit #1 to determine the inlet temperature measurement.

FLUE GAS TEMPERATURE


Flue gas measurement is used to establish the state of the combustion products leaving the boiler thought the flue in the calculation of combustion efficiency. In an effort to get a better idea of the average temperature within the flue, a grid of 9 thermocouples was used to take simultaneous exhaust gas temperature readings.



Three thermocouples were spaced evenly apart and fixed to a slender rod that is then inserted into the flue. This process was repeated three times to get a total of nine temperature measurements in a grid arrangement within the flue.

FIGURE 24. FLUE GAS THERMOCOUPLE GRID ARRANGEMENT


FIGURE 25. LOCATION OF FLUE GAS TEMPERATURE AND CO2 SAMPLING

CO2 CONCENTRATION


Carbon dioxide forms during the combustion process, and is removed from the boiler through the flue. Percentage concentration of carbon dioxide in the flue gas is measured in order to calculate boiler combustion efficiency.


TABLE 28. STD. 155P FLUE CARBON DIOXIDE CONCERTRATION MEASUREMENT REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy


Type Range

Specified Gas Chemistry

Carbon Dioxide 0.2% CO2

± 0.1% CO2

Orsat or Meter 0 to 15% CO2


CO2 concentration is measured directly from exhaust gases in the flue just downstream of the thermocouple grid for unit 2, and is measured just downstream of the draft diverter in four separate locations translating down the length of the burner of unit 1.


FIGURE 26. LANCOM III EXHAUST GAS ANALYZER USED FOR TAKING FLUE CO2 MEASUREMENTS


Factory calibration is maintained on this unit through sending it in for yearly service/calibration. According to the manufacturer, the uncertainty in %CO2 from a factory calibrated Lancom III exaust gas analyzer is 0.5% CO2.


TABLE 29. IDENTIFYING SOURCES OF ERROR IN FLUE GAS CARBON DIOXIDE MEASUREMENT

Error Sources Bias Precision 1. Error in calibration standard B1 2. Error due to fluctuating test data S2

Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty of 95% confidence. The uncertainty result below does not factor in sources of spatial uncertainty in atmospheric units.

TABLE 30. RESULTING UNCERTAINTY IN PERCENTAGE OF CO2 INSTRUMETATION



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?

CO2 (%) 0.525% 0.100% No

Note: This uncertainty does not factor in spatial uncertainty, which is especially significant for atmospheric units.


RELATIVE HUMIDITY


Relative humidity is another parameter necessary to fix the conditions of the intake air for calculation of combustion efficiency.


TABLE 31. STD. 155P RELATIVE HUMIDITY MEASUREMENT REQUIREMENTS

Property Measured

Item Measured

Minimum Resolution

Minimum Accuracy


Type Range

Specified Relative Humidity Ambient Air 1.00% ± 2% of

full scale Psychrometer 10-100 %

The manufacturer of the chilled mirror hygrometer states an accuracy of +/- 0.36F dew point temperature. At 75 F dry bulb temperature, this corresponds to an uncertainty of about +/- 1% relative humidity.


A General Eastern Optica chilled mirror hygrometer was used to measure relative humidity. An analog output is read from this unit using the labview data acquisition system.


TABLE 32. IDENTIFYING SOURCES OF ERROR IN RELATIVE HUMIDITY MEASUREMENT

Error Sources Bias Precision 1. Error in calibration standard B1 2. Error due to fluctuating test data S2

Precision and fossilized error resulting from repeatability of calibrations discussed earlier, as well as precision error due to fluctuating test data discussed earlier are root sum squared together with the error above to obtain an overall uncertainty of 95% confidence.

TABLE 33. RESULTING UNCERTAINTY IN RELATIVE HUMIDITY MEASUREMENT



Test Parameter


Test Parameter

Meets ASHRAE Std

155 Requirement?


Relative Humidity (%) 1.03% 2.00% Yes

JACKET LOSS TEST PROCEDURES The Jacket Losses were calculated per the methods outlined in ASHRAE 103-2007 8.6.1. The jacket was divided into sections and the temperature of each section was measured. A spreadsheet was used to calculate the heat loss for each section using equation 8.6.1.3.

Figure 12 was used to create equations to approximate the radiation coefficient on each section surface.


Similarly, the convection coefficient was approximated by an equation based on Figure 12. The convection coefficient equation is based on the curve in Figure 12 when the ambient temperature is 70 degrees F. Most of the

y = 0.0096x + 0.37 R² = 0.836

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1 10 100

Horizontal Facing Up

y = 0.0061x + 0.27 R² = 0.815

0

0.2

0.4

0.6

0.8

1

1 10 100

Vertical

y = 0.0046x + 0.2 R² = 0.8189

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

1 10 100

Horizontal Facing Down


jacket losses were calculated at ambient temperatures of 65-70 degrees. The exception to this is 1.02 which was run at an ambient temperature of about 95 degrees. The curve for 100 degree ambient temperature would have been more appropriate in this instance.

The emissivity was approximated from 8.6.1.2.

y = 0.8539e0.0028x R² = 0.999

0.8

0.9

1

1.1

1.2

1.3

1.4

1.5

1.6

0 50 100 150 200 250

T_ambient 70F T_ambient 70F


UNIT 2 Calculating the area of the jacket proved not straightforward, particularly for Unit 2; the geometry of the boiler is such that there are many irregular surfaces. Sketches were used in the lab to indicate temperatures measured at each section like. Dimensional drawings were then used to calculate the area at each section. For example the sketch for data readings taken for Back of Unit 2 with the dimensional drawing to determine the area of each section.

Section 8.6.1.1 Outlines using 0.25 square foot sections where the temperature difference between adjacent sections is >10˚F if the surface temperature is <100˚F above room temperature or >20˚F if the surface temperature is >100˚F above room temperature. If the temperatures of adjacent sections have lower differentials they may be grouped together. For the calculations, sections with similar temperatures were grouped together where was convenient. For the calculation for the back of Unit 2 in test 2.01.00 was broken divided into 7 convenient sections of similar temperatures. The areas, temperatures, emissivities, and orientations were input into a spreadsheet that calculated radiation and convection coefficients and the heat loss of each section.

BACK Area, SF

Temperature

dT, F Orientation

hc, Btu/(h*ft2*F) Material

Emissivity

hrs, Btu/(h*ft2*F) Hs, Btu/h

1 4.63 85.7 7.7 vertical 0.32 galv iron, 0.23


bright 0.25 20

2 0.46 80.6 2.6 vertical 0.29 galv iron, bright 0.23

0.25

1


0.25

4


0.26

2


0.26

4


0.25

1


0.25

0

Calculating the area of curved surfaces and the high temperature differentials measured between small adjacent sections leads to uncertainty in these measurements. Unit 2, below, had a complex geometry and the areas in some cases were difficult to define.

Unit 1 had a simpler geometry but in some cases temperatures taken ~6” apart were >50˚F apart as shown below in the sketch from test 1.05.


UNIT 1 Measuring jacket losses for Unit 1 was also problematic and highly subjective. The biggest issue is what is the jacket? The boiler has multiple layers of ventilated side panels designed to assist with stack drafting. Sealing the vents was not practical and would have significantly affected boiler operation. Removing panels also affects performance. Test 1.01 and 1.05 are the same expect 1.01 has the panels on and 1.05 has them removed.


FIGURE 27. UNIT 1 WITH SIDEPANELS


FIGURE 28. UNIT 1 WITHOUT SIDEPANELS

IDLING TESTS Idling tests for Unit 2 were performed by allowing the boilers internal controls to control the firing rate. The boiler thus used its own internal aquastat and followed defaults pre-purge, post-purge, ignition, etc. We were able to adjust the differential using the keypad. The boiler apparently also has some adjustable parameters to adjust how long the boiler stays at minimum fire after ignition before it releases to PID control. Unfortunately we were unable to adjust these parameters.


RESULTS UNIT 2 STEADY STATE TEST RESULTS

Figure 29 shows all the steady state test results for Unit 2. The x-axis is each combination of sensors. There are (3) Tin sensors, (2) Tout sensors, and (2) gas meters for a total of 12 thermal efficiency sensor combinations. There are two combustion efficiency sensor combinations and one sensor combination for combustion minus jacket losses. Each efficiency also includes error bars for the total uncertainty.

FIGURE 29. UNITS 2 STEADY STATE TEST RESULTS

Figure 30 is a subset of Figure 29 representing a single set of sensors. As Figure 29 shows there is very good agreement between the sensor combinations so Figure 30 essentially captures all the information in Figure 29 but in an easier to read format.



Some observations about Figure 30:

1. The thermal efficiency follows the expected pattern between tests, e.g. one would expect thermal efficiency to go up from 2.02 to 2.03.

2. Combustion efficiency does not entirely follow the expected pattern. The combustion efficiency for 2.03 is expected to be considerably higher. This could be an error in the test execution or due to an unaccounted for source of uncertainty (e.g. spatial variation in CO2).

3. Thermal efficiency is fairly consistent between 2.01.00 and 2.01.01 but combustion efficiency is not. The difference between these 2 tests is that the CO2 variation was higher than allowed by Standard 155P during the test period. The fact that thermal efficiency is consistent and combustion efficiency is not consistent implies that combustion efficiency may not be a good indicator of thermal efficiency and/or that the combustion uncertainty does not capture all combustion uncertainty.


FIGURE 31. OVERALL UNCERTAINTY FOR EACH SENSOR COMBINATION FOR TEST 2.01.00

UNIT 1 STEADY STATE TEST RESULTS Figure 32 shows all the steady state test results for Unit 1. The x-axis is each combination of sensors. There are (3) Tin sensors, (2) Tout sensors, and (2) gas meters for a total of 12 thermal efficiency sensor combinations. There are two combustion efficiency sensor combinations and one sensor combination for combustion minus jacket losses. Each efficiency also includes error bars for the total uncertainty.

Measurement Approach

Overall uncertainty (+/- % absolute

efficiency)Thermal Efficiency TS1/TR1 - 1500CFH Gas Volume Meter 1.019%Thermal Efficiency TS1/TR2 - 1500CFH Gas Volume Meter 1.023%Thermal Efficiency TS2/TR1 - 1500CFH Gas Volume Meter 0.986%Thermal Efficiency TS2/TR2 - 1500CFH Gas Volume Meter 0.990%Thermal Efficiency TS3/TR1 - 1500CFH Gas Volume Meter 0.979%Thermal Efficiency TS3/TR2 - 1500CFH Gas Volume Meter 0.958%Thermal Efficiency TS1/TR1 - 800CFH Gas Volume Meter 1.018%Thermal Efficiency TS1/TR2 - 800CFH Gas Volume Meter 1.012%Thermal Efficiency TS2/TR1 - 800CFH Gas Volume Meter 0.974%Thermal Efficiency TS2/TR2 - 800CFH Gas Volume Meter 0.979%Thermal Efficiency TS3/TR1 - 800CFH Gas Volume Meter 0.968%Thermal Efficiency TS3/TR2 - 800CFH Gas Volume Meter 0.972%Combustion Efficiency - 1500CFH Gas Volume Meter 0.259%Combustion Efficiency - 800CFH Gas Volume Meter 0.259%


FIGURE 32. UNIT 1 STEADY STATE TEST RESULTS

Figure 33 is a subset of Figure 32, reprensenting a single sensor combination.



TEST DISQUALIFICATION Not all of the steady state tests meet the tolerances required in Standard 155P in order to be considered a valid test, i.e. some of the test would be “disqualified” due to higher than allowed variations in CO2, etc.

INSERT QUALIFICATIONS

UNCERTAINTY ANALYSES

SUMMARY OF UNCERTAINTY IN EACH MEASURED PARAMETER Included in the table below is the realized uncertainty in each test parameter, along with the determination of whether or not the parameter met the accuracy requirements of for a typical steady state test (test 2.01.00 in this case).

TABLE 34. COMPARISON OF TEST 2.01.00 MEASUREMENT PARAMETER UNCERTAINTY TO STD. 155P REQUIREMENTS


Actual Uncertainty

in Test Parameter

Required Uncertainty

in Test Parameter

Meets ASHRAE Std 155?

Supply Water Temperature 1 (°F) 0.168 0.200 Yes Supply Water Temperature 2 (°F) 0.114 0.200 Yes Supply Water Temperature 3 (°F) 0.107 0.200 Yes Return Water Temperature 1 (°F) 0.107 0.200 Yes Return Water Temperature 2 (°F) 0.114 0.200 Yes Natural Gas Temperature - 1500 CFH Meter (°F) 0.133 1.000 Yes Natural Gas Temperature - 800 CFH Meter (°F) 0.122 1.000 Yes Ambient Temperature (°F) 0.223 1.000 Yes Burner Inlet Temperature (°F) 0.160 1.000 Yes Flue Gas Temperature - TC Grid (°F) 0.318 2.000 Yes Water Volumetric Flow (% hourly rate) 0.302% 0.250% No Water Density (lb./cf) 0.010 n/a Yes 1500 CFH Gas Volumetric Flow (% hourly rate) 0.331% 0.250% No 800 CFH Gas Volumetric Flow (% hourly rate) 0.305% 0.250% No Barometric Pressure (psia) 0.020 0.025 Yes 1500CFH Pressure Compensation (inches H2O) 0.024 0.100 Yes 800CFH Pressure Compensation (inches H2O) 0.024 0.100 Yes Boiler Power Consumption (% of kW reading) 1.00% 1% No Mixing Pump Consumption (% of kW reading) 1.53% 1.00% No CO2 (%) 0.525% 0.100% No Relative Humidity (%) 1.01% 2.00% Yes Boiler Condensate Flow Rate (lb./hr.) n/a n/a Yes Flue Condensate Flow Rate (lb./hr.) n/a n/a Yes Higher Heating Value (BTU/ft3) 1.00% 1.00% Yes


FIGURE 34. OVERALL UNCERTAINTY AND UNCERTAINTY CONSTITUENTS FOR 2.01.00 SENSOR COMBINATION TS1/TR1, 800 METER

Measurement parameters that did not meet the uncertainty requirements of Std. 155P include:

· Water Volumetric Flow (gpm)

· Gas Volumetric Flow (ft3/hr.)

· Boiler Power and Mixing Pump Power Consumption (% of kW reading)

· CO2 (%)

DITHERING TEST PARAMETER UNCERTAINTY A dithering routine can be performed to improve understanding of the impact of individual measurement parameters on the overall uncertainty of a test. In this case, each measurement parameter used in the calculation of boiler thermal and combustion efficiency was varied, and the individual contribution of uncertainty in each measurement parameter on the overall uncertainty in thermal and combustion efficiency was determined. More detail on dithering is available in Ronald Dieck’s “Measurement Uncertainty: Methods and Applications” textbook.


The table below illustrates a portion of the dithering routine, as only the temperature instrumentation is being displayed as an example. Each inlet and outlet temperature measurement was adjusted upward by the uncertainty quantified in each measurement, which are the values highlighted in pink in the table below. Adjusting the inlet and outlet temperature individually result in thermal efficiency chaging by approximately 0.3% (inlet temperature) and -0.25% (outlet temperature). Comparison of these changes in thermal and combustion efficiency resulting from changing each test parameter by its uncertainty one at a time identifies which measurement parameter contributes most to the overall uncertainty in thermal and combustion efficiency.

TABLE 35. DITHERING TEMPERATURE MEASUREMENT UNCERTAINTY

2.01.01 Bias Limits

Test Measurement: Inlet Water Temperature 1 (°F) 141.26 0.17 Inlet Water Temperature 2 (°F) 141.18 0.11 Inlet Water Temperature 3 (°F) 141.32 0.10 Outlet Water Temperature 1 (°F) 180.04 0.10 Outlet Water Temperature 2 (°F) 180.15 0.11 Natural Gas Temperature - 1500 CFH Meter (°F) 68.210 0.13 Natural Gas Temperature - 800 CFH Meter (°F) 76.906 0.11 Ambient Temperature (°F) 85.68

0.22

Burner Inlet Temperature (°F) 84.85

0.16 Thermal Efficiency TS1/TR1 - 1500CFH Gas Volume Meter 84.34% 0.36% 0.00% 0.00% -0.23% 0.00% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS1/TR2 - 1500CFH Gas Volume Meter 84.58% 0.36% 0.00% 0.00% 0.00% -0.24% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS2/TR1 - 1500CFH Gas Volume Meter 84.51% 0.00% 0.24% 0.00% -0.23% 0.00% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS2/TR2 - 1500CFH Gas Volume Meter 84.75% 0.00% 0.24% 0.00% 0.00% -0.24% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS3/TR1 - 1500CFH Gas Volume Meter 84.21% 0.00% 0.00% 0.23% -0.23% 0.00% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS3/TR2 - 1500CFH Gas Volume Meter 84.447% 0.00% 0.00% 0.23% 0.00% -0.24% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS1/TR1 - 800CFH Gas Volume Meter 84.32% 0.36% 0.00% 0.00% -0.23% 0.00% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS1/TR2 - 800CFH Gas Volume Meter 84.56% 0.36% 0.00% 0.00% 0.00% -0.24% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS2/TR1 - 800CFH Gas Volume Meter 84.48% 0.00% 0.24% 0.00% -0.23% 0.00% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS2/TR2 - 800CFH Gas Volume Meter 84.72% 0.00% 0.24% 0.00% 0.00% -0.24% -0.02% 0.00% 0.00% 0.00% Thermal Efficiency TS3/TR1 - 800CFH Gas Volume Meter 84.18% 0.00% 0.00% 0.23% -0.23% 0.00% -0.02% 0.00% 0.00% 0.00%

Thermal Efficiency TS3/TR2 - 800CFH Gas Volume Meter 84.42% 0.00% 0.00% 0.23% 0.00% -0.24% -0.02% 0.00% 0.00% 0.00% Combustion Efficiency - 1500CFH Gas Volume Meter 83.98% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% -0.01% Combustion Efficiency - 800CFH Gas Volume Meter 83.98% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% -0.01%


UNCERTAINTY IN ACTUAL TEST MEASUREMENTS

The table below presents the results of the complete dithering routine for a typical steady state test. Test parameters that play the largest role in thermal and combustion efficiency uncertainty will be discussed individually.

TABLE 36. DITHERING MEASUREMENT UNCERTAINTY – TEST 2.01.01



Test Parameter

Uncertainty in Thermal Efficiency

(+/- percent absolute

efficiency)

Uncertainty in Combustion Efficiency

(+/- percent absolute

efficiency) Supply Water Temperature 1 (°F) 0.168 0.364% 0.000% Supply Water Temperature 2 (°F) 0.113 0.246% 0.000% Supply Water Temperature 3 (°F) 0.106 0.231% 0.000% Return Water Temperature 1 (°F) 0.106 0.229% 0.000% Return Water Temperature 2 (°F) 0.113 0.246% 0.000% Natural Gas Temperature - 1500 CFH Meter (°F) 0.130 0.021% 0.000% Natural Gas Temperature - 800 CFH Meter (°F) 0.114 0.018% 0.000% Ambient Temperature (°F) 0.223 0.000% 0.000% Burner Inlet Temperature (°F) 0.160 0.000% 0.006% Flue Gas Temperature - TC Grid (°F) 0.316 0.000% 0.011% Water Volumetric Flow (% hourly rate) 0.302% 0.252% 0.000% Water Density (lb./cf) 0.010 0.014% 0.000% 1500 CFH Gas Volumetric Flow (% hourly rate) 0.334% 0.281% 0.000% 800 CFH Gas Volumetric Flow (% hourly rate) 0.305% 0.257% 0.000% Barometric Pressure (psia) 0.020 0.114% 0.000% 1500CFH Pressure Compensation (inches H2O) 0.024 0.005% 0.000% 800CFH Pressure Compensation (inches H2O) 0.024 0.003% 0.000% Boiler Power Consumption (% of kW reading) 1.42% 0.003% 0.000% Mixing Pump Consumption (% of kW reading) 1.53% 0.000% 0.000% CO2 (%) 0.525% 0.000% 0.312% Relative Humidity (%) 1.03% 0.000% 0.074% Boiler Condensate Flow Rate (lb./hr.) n/a 0.000% 0.000% Flue Condensate Flow Rate (lb./hr.) n/a 0.000% 0.000% Higher Heating Value (BTU/ft3) 1.00% 0.833% 0.000%

Test measurement parameters that have a significant (>0.25%) impact on thermal and combustion efficiency uncertainty:

· Water Volumetric Flow (gpm)

· Gas Volumetric Flow (ft3/hr.)

· Water Temperature (F)

· Higher Heating Value

· CO2 (%)


UNCERTAINTY IN STD. 155P REQUIREMENTS The table below presents the results of the complete dithering routine using the uncertainty requirements of Std. 155P. Both a high and low temperature test is analyzed to include the impact of condensate measurement uncertainty in the overall uncertainty of combustion efficiency. Test parameters that play the largest role in thermal and combustion efficiency uncertainty will be discussed individually.

TABLE 37. UNCERTAINTY IN STD 155P - HIGH FIRE, HIGH TEMPERATURE TEST (NO CONDENSATE FORMATION)



efficiency) Thermal Efficiency 1.114% Combustion Efficiency 0.225%

TABLE 38. UNCERTAINTY IN STD 155P - HIGH FIRE, HIGH TEMPERATURE TEST (NO CONDENSATE FORMATION)


Uncertainty in Thermal

Efficiency (+/- percent absolute

efficiency)

Uncertainty in Combustion


efficiency) Inlet Water Temperature (°F) 0.437% 0.000% Outlet Water Temperature (°F) 0.437% 0.000% Natural Gas Temperature (°F) 0.159% 0.000% Burner Inlet Temperature (°F) 0.000% 0.080% Flue Gas Temperature - TC Grid (°F) 0.000% 0.159% Water Volumetric Flow (% hourly rate) 0.211% 0.000% Water Density (lb./cf) 0.000% 0.000% Gas Volumetric Flow (% hourly rate) 0.210% 0.000% Barometric Pressure (psia) 0.142% 0.000% Natural Gas Pressure Compensation (inches H2O) 0.181% 0.000% Boiler Power Consumption (% of kW reading) 0.003% 0.000% Mixing Pump Consumption (% of kW reading) 0.000% 0.000% CO2 (%) 0.000% 0.137% Relative Humidity (%) 0.000% 0.080% Boiler Condensate Flow Rate (lb./hr.) 0.000% 0.000% Higher Heating Value (BTU/ft3) 0.833% 0.000%


TABLE 39. UNCERTAINTY IN STD 155P - HIGH FIRE, LOW TEMPERATURE TEST (CONDENSATE FORMATION OCCURS)


Overall uncertainty (+/-

% absolute efficiency)

Thermal Efficiency 1.136% Combustion Efficiency 0.308%

TABLE 40. UNCERTAINTY IN STD 155P - HIGH FIRE, LOW TEMPERATURE TEST (CONDENSATE FORMATION OCCURS)


Uncertainty in Thermal


efficiency)

Uncertainty in Combustion


efficiency) Inlet Water Temperature (oF) 0.436% 0.000% Outlet Water Temperature (oF) 0.438% 0.000% Natural Gas Temperature (°F) 0.164% 0.003% Burner Inlet Temperature (°F) 0.000% 0.115% Flue Gas Temperature - TC Grid (°F) 0.000% 0.227% Water Volumetric Flow (% hourly rate) 0.217% 0.000% Gas Volumetric Flow (% hourly rate) 0.216% 0.002% Barometric Pressure (psia) 0.145% 0.003% Gas Volumetric Flow Pressure Compensation (inches H2O) 0.182% 0.004% Boiler Power Consumption (% of kW reading) 0.000% 0.000% Mixing Pump Consumption (% of kW reading) 0.000% 0.000% CO2 (%) 0.000% 0.000% Relative Humidity (%) 0.000% 0.172% Boiler Condensate Flow Rate (lb./hr.) 0.000% -0.008% Higher Heating Value (BTU/ft3) 0.856% 0.008%

Std. 155P parameters that have a significant (>0.25%) impact on thermal and combustion efficiency uncertainty:

· Inlet/Outlet Water Temperature (oF) · Higher Heating Value (BTU/ft3)


UNDERSTANDING AND MITIGATING WATER FLOW UNCERTAINTY

NO AVAILABLE CALIBRATION STANDARD

PG&E’s Advanced Technology Performance Lab where the tests were performed has the advantage of being able to perform a multiple point water flow meter calibration in series with a NIST traceable coriolis flow standard. This is a unique capability that would generally not be available to a facility that would perform boiler testing. Had the coriolis meter not been available as a standard for calibrating the magnetic flow meter used during testing, the uncertainty in flow reading during a low fire (about 5 gpm) and high fire test (about 22 gpm) would exceed 4.00% and 1.00% respectively due to the size and type of flow meter selected.

FIGURE 35. DEVIATION (% OF INDICATION) BETWEEN CORIOLIS STANDARD AND MAGNETIC FLOW METER WITHOUT CALIBRATION DATA PROCESSING CORRECTION

CALIBRATION STANDARD USED TO CORRECT RAW METER READING

With the availability of a multiple point calibration, the raw data was able to be corrected using a least squares analysis of both the pre and post calibration data. Using this correction, the overall uncertainty in water flow measurement during a typical test is maintained at an uncertainty of 0.4% or below.

-8.00%

-7.00%

-6.00%

-5.00%

-4.00%

-3.00%

-2.00%

-1.00%

0.00%0.000 20.000 40.000 60.000 80.000

Devi

atio

n be

twee

n M

ag M

eter

and

Cor

iolis

St

d.

(per

cent

of i

ndic

atio

n)

Coriolis Standard Flowrate (gpm)


FIGURE 36. DEVIATION (% OF INDICATION) BETWEEN CORIOLIS STANDARD AND RAW MAGNETIC FLOW METER WITH CALIBRATION DATA PROCESSING CORRECTION

COMPARING MAGNETIC FLOW METER RAW FACTORY CALIBRATION TO CORRECTED PERFORMANCE USING CALIBRATION STANDARD

FIGURE 37. COMPARISON BETWEEN RAW AND CORRECTED DEVIATION (% OF INDICATION) BETWEEN CORIOLIS STANDARD AND MAGNETIC FLOW METER

-0.40%

-0.30%

-0.20%

-0.10%

0.00%

0.10%

0.20%

0.30%

0.40%

0.50%

0.0 20.0 40.0 60.0 80.0

Dev

iati

on

in L

SQ

Fit

an

d S

td.

Flo

w

(% o

f in

dic

atio

n)


-1.0%0.0%1.0%2.0%3.0%4.0%5.0%6.0%7.0%8.0%

0.0 20.0 40.0 60.0 80.0Dev

iati

on

in L

SQ

Fit

an

d

Std

. Fl

ow

(

% o

f in

dic

atio

n)


Corrected Data Raw Data


TABLE 41. COMPARISON OF THERMAL EFFICIENCY CALCULATION USING EITHER RAW OR CORRECTED DATA

Calculated Parameter

Supply Temperature Measurement

Location

Return Temperature Measurement

Location Raw Water Flow Rate

Corrected Water

Flow Rate Thermal Efficiency 1 1 83.5% 84.3% Thermal Efficiency 1 2 83.7% 84.6% Thermal Efficiency 2 1 83.7% 84.5% Thermal Efficiency 2 2 83.9% 84.8% Thermal Efficiency 3 1 83.4% 84.2% Thermal Efficiency 3 2 83.6% 84.4% Thermal Efficiency 1 1 83.5% 84.3% Thermal Efficiency 1 2 83.7% 84.6% Thermal Efficiency 2 1 83.6% 84.5% Thermal Efficiency 2 2 83.9% 84.7% Thermal Efficiency 3 1 83.3% 84.2% Thermal Efficiency 3 2 83.6% 84.4%

PERFORMANCE OF A MULTIPLE FLOW METER SELECTION

Flow rates required during a steady state test will vary amongst different boilers, dependent upon boiler rating and turndown ratio. One single water flow meter may not have the ability to turn down and still meet the accuracy requirements of the standard for all of these conditions. The Badger M2000 used during this testing effort is oversized for its application, as evident in the data in Figure 37. Since it is not typical for a facility to have the ability to calibrate to a flow standard in place and account for hysteresis in a single meter, another option for meeting accuracy requirements of the standard must be determined.

One possible solution to address the concern of water flow meter turndown accuracy is to install a combination of flow meters in parallel with capacities and turndown ratings covering all anticipated tests. Some water flow meter manufacturers advertise accuracies of 0.2% throughout there range. If such a factory rated accuracy is achievable, water flow measurements will meet standard 155P accuracy requirements.

An additional solution could involve a variable flow recirculation loop. Water sent to the boiler inlet, commonly city water, can be mixed with water recirculated from the boiler outlet. If the rate at which water is recirculated from the boiler output can vary, required Std. 155P test conditions can be met with a single meter measuring the flow rate of city water sent to the boiler. A low fire test may require significant recirculation to maintain required Std. 155P conditions, while a high fire test will require less, both potentially with similar city water flow rates. This solution will also result in a reduction in the uncertainty of the temperature difference measurement.


TABLE 42. IMPACT OF EASING WATER VOLUMETRIC FLOW ACCURACY REQUIREMENT ON OVERALL UNCERTAINTY



efficiency) Thermal Efficiency - 0.25% Hourly Rate Accuracy 1.114% Thermal Efficiency - 0.375% Hourly Rate Accuracy 1.139% Thermal Efficiency – 0.5% Hourly Rate Accuracy 1.173%

UNDERSTANDING AND MITIGATING GAS VOLUMETRIC FLOW UNCERTAINTY Meeting the natural gas volumetric flow accuracy requirement of Std. 155P was not possible with a standard rotary volume meter. As indicated in Figure 38, meter accuracy degrades significantly below 10 percent of the meters rated capacity. Under the current requirements of 155P, overall uncertainty in thermal efficiency is over 1%. Relaxing the accuracy of the natural gas volume meter from 0.25% of hourly rate to 0.5% of hourly rate, which was achieved using a calibrated rotary volume meter, only increases the uncertainty in the standard by hundredths of a percent overall uncertainty. Further relaxing the requirement to 1% would allow even more meters to be used for testing, and increases the overall uncertainty in thermal efficiency by about .25%.

TABLE 43. IMPACT OF EASING NATURAL GAS VOLUMETRIC FLOW ACCURACY REQUIREMENT ON OVERALL UNCERTAINTY



efficiency) Thermal Efficiency - 0.25% Hourly Rate Accuracy 1.114% Thermal Efficiency - 0.375% Hourly Rate Accuracy 1.139% Thermal Efficiency - 0.5% Hourly Rate Accuracy 1.172% Thermal Efficiency - 1.0% Hourly Rate Accuracy 1.375%

UNDERSTANDING AND MITIGATING HIGHER HEATING VALUE UNCERTAINTY TABLE 44. IMPACT OF EASING NATURAL GAS HIGHER HEATING VALUE ACCURACY REQUIREMENT ON OVERALL

UNCERTAINTY



efficiency) Thermal Efficiency - 1.0% Accuracy in HHV 1.114% Thermal Efficiency - 0.75% Accuracy in HHV 0.970% Thermal Efficiency - 0.5% Accuracy in HHV 0.850%

Weekly reported utility data was used to establish natural gas HHV for testing. The standard deviation in this data was 1.78 cf, or approximately 0.2%, over the past seven weeks of reporting. Overall uncertainty in thermal efficiency would decrease


almost 0.3% if the accuracy requirement for HHV in Std. 155P was reduced from 1% to 0.5%.

UNDERSTANDING AND MITIGATING FLUE CO2% UNCERTAINTY CO2 concentration in the flue gases of the atmospheric unit deviated by as much as 1.29% depending on where the combustion measurement was taken along the length of the burner. During the two hour steady state test, the combustion probe was moved from location 1 to location 4, residing in each location for about 30 minutes.

FIGURE 39. FOUR SAMPLING LOCATIONS ALONG THE BURNER OF UNIT 1

0

100

200

300

400

500

600

700

800

900

0 1000 2000 3000 4000 5000 6000 7000 8000

%CO

2 *

100

Seconds


FIGURE 40. CONCENTRATION OF CARBON DIOXIDE IN FLUE GASES OF ATMOSPHERIC BOILER WITH FOUR DIFFERENT SAMPLING LOCATIONS ALONG THE BURNER FOR TEST 1.02

TABLE 45. IMPACT OF SPATIAL UNCERTAINTY IN ATMOSPHERIC BOILER ON OVERALL UNCERTAINTY OF COMBUSTION EFFICIENCY



efficiency) Combustion Efficiency - 0.1% Std. 155P Accuracy in CO2% 0.238% Combustion Efficiency - 1.29% Spatial Uncertainty in CO2% 1.686%

TEMPERATURE INSTRUMENTATION OPERATIONAL CHECKS Periodically performing temperature instrumentation operational checks (“op-checks”) will ensure individual probes have not drifted since they were initially calibrated. Upon post calibration of temperature instrumentation, Boiler Inlet Temperature RTD 1 had drifted to the point where its reading deviated from the calibration standard reading by almost 0.3F at 150 oF, outside the tolerance of Std. 155P. Had an op-check been performed before the test, this issue would have been resolved. Fortunately, two more redundant inlet temperature sensors are available for calculating thermal efficiency.

MIXING VERIFICATION TEMPERATURE ARRAY Per the requirements of Standard 155P, new mixing verification array end caps were fabricated, with fittings placed 2/3 the way between the centerline of the pipe and the pipe wall evenly spaced at every 90 degrees.


FIGURE 41. MIXING VERIFICATION ARRAY END CAP

IMPACT OF SAMPLING INTERVAL ON TEST UNCERTAINTY

TABLE 46. IMPACT OF SAMPLING INTERVAL ON OVERALL THERMAL AND COMBUSTION EFFICIENCY

Selection of a sampling interval of at least 1 minute will mitigate the impacts of precision error on overall test uncertainty. This calculation was performed by reducing the degrees of freedom of each measurement parameter though reducing the number of data points. Standard deviation in measured data from actual test data using 1 and 2 second sampling intervals was used to perform this analysis.

Sampling Interval

Number of Data Points


% absolute thermal

efficiency)


% absolute combustion efficiency)

5 sec 2401 1.018% 0.707% 10 sec 1201 1.020% 0.708% 1min 121 1.059% 0.712% 5min 25 1.215% 0.734%

10min 13 1.388% 0.765% 15min 9 1.547% 0.808% 30min 5 1.989% 0.948%

JACKET LOSSES Table 47 shows the measured jacket losses as a percentage of the full fire input rate. It also shows the possible range of jacket losses based on rough estimates of error in measurements. While these error estimates are rough estimates it is pretty clear that the jacket losses could easily be half or double what we measured based on how measurements were taken.

TABLE 47. JACKET LOSS RESULTS

Test ID Unit Fire

Rate HWT Troom Jacket

Losses JL-error JL+error Comments

2.01.00 2 Hi Hi Hi 85 0.2% 0.2% 0.5% 2.01.01 2 Hi Hi Hi 85 0.2% 0.2% 0.3% 2.02 2 Lo Hi Lo 65 0.9% 0.8% 1.4% Expecting to see hi jacket losses 1.01 1 Hi Hi Lo 65 0.7% 0.6% 1.0% Expecting relatively high jacket losses 1.02 1 Hi Hi Hi 95 1.4% 1.2% 2.0% Expecting relatively low jacket losses 1.05 1 Hi Hi Lo 65

1.9% 1.7% 2.9% With side panels off with jacket loss of inner panels


IDLING TEST RESULTS Due to time and budget constraints idling tests were largely inconclusive and likely will need to be re-run in the next phase of testing.


OBSERVATIONS ADDITIONAL UNCERTAINTY IN COMBUSTION EFFICIENCY

It is unlikely that there is any unaccounted for uncertainty in the thermal efficiency uncertainty calculations. For example, spatial uncertainty in water temperature has been addressed with mixing requirements. The uncertainty in the HHV, gas flow, water flow and water temperature are fully accounted for. There are no other significant factors that could affect thermal efficiency.

Combustion efficiency, on the other hand, is likely to have significant additional uncertainty that is not accounted for in the uncertainty calculations, including but not limited to the following:

1. Uncertainty in equation constants. The combustion efficiency equation includes several constants that clearly have assumptions imbedded in them. For example, why does the combustion efficiency equation for oil-fired boilers include HHVoil, carbon content of fuel oil, and hydrogen content of fuel oil, but the combustion efficiency equation for gas fired boilers does not include HHVgas? Clearly there is an assumption imbedded for the HHV and likely other imbedded assumptions.

2. AHRI maintains a database with over 100 boiler thermal and combustion efficiency ratings using the BTS-2000 method of test. Something like 40% of the boilers in the database have higher thermal efficiency than combustion efficiency, which of course is not physically possible. Statistically speaking, thermal efficiency measurement accuracy alone is unlikely to explain why such a large fraction have thermal above combustion. This could be further proof of additional uncertainty in combustion efficiency.

3. Spatial uncertainty in CO2 measurement. Test 1.02 on Unit 1 (outdoor atmospheric boiler) showed huge spatial variations in CO2 concentration in the flue (from 6.5% to 8.0%) which resulted in overall uncertainty in combustion efficiency of over 1.7% (significantly higher than the overall uncertainty in thermal efficiency). Unfortunately, all CO2 readings for Unit 2 (forced draft condensing boiler) were taken at a single location in the flue so spatial uncertainty was not evaluated for Unit 2.

4. Flue gas and flue temperature simply cannot be measured reliably for some boilers (e.g. outdoor atmospheric boilers) due to spatial uncertainty, ambiguity about where to take readings and access to reading locations. For Unit 1 it was not possible to access the preferred reading location without taking off part of the boiler.

The expression “better the devil you know, than the devil you don't” comes to mind when comparing thermal and combustion efficiency. Thermal efficiency uncertainty may be higher than we would like but we can be reasonably confident in that uncertainty. Combustion minus Jacket is likely to have additional unknown uncertainty.

MISCELLANEOUS · Unit 2 had trouble reaching its maximum turndown rating of 20% fire. While

attempting to turn the boiler down this far, the boiler would make a


resonating noise and appear to become unstable. This behavior may have been caused by how the boiler was tuned.

· Gas temperature increased siginificantly from one meter to the next, leading to some concerns with the placement of the temperature compensation probe.CO2 concentration varied by at least 1% along the length of the burner of unit 1.

· When measuring jacket losses, inconsistent contact with the jacket surface may introduce measurement uncertainty.

· Recirc pump –

· Stratification -

EVALUATIONS In addition to the main analyses related to steady state efficiency uncertainty, a number of “side” analyses and tests were performed.

EFFICIENCY SNAPSHOTS

All Steady State tests were run for the required 2 hours. The efficiency results presented above are based on the average sensor readings for the entire test period. Figure 42 shows efficiency snapshots for 30 minute periods during the 2 hour test for 2.01.01. Jacket losses were only measured once so they are assumed to be constant for each interval. Combustion efficiency is more stable than thermal efficiency but thermal is still relatively stable (within the error bars).


FIGURE 42. EFFICIENCY SNAPSHOTS FOR 2.01.01 (HIGH FIRE, HIGH TEMPERATURE)

Figure 43 shows similar snapshops for the low fire, low temperature test. Jacket losses were not measured for this test. Mass flow rate for condensate was only measured once for the 2 hour period and thus is assumed to be the same for the intervals as for the full test. Combustion efficiency is again more stable than thermal efficiency but both are within their error bars.


FIGURE 43. EFFICIENCY SNAPSHOTS FOR 2.04 (LOW FIRE, LOW TEMPERATURE)

NATURAL GAS TEMPERATURE SPATIAL UNCERTAINTY

Natural gas temperature has a relatively small effect on the overall uncertainty if there is not spatial uncertainty. See red column below.


However, significant spatial variations in the natural gas temperature were seen during testing. For example, gas temperature can increase 10oF from the first and last natural gas temperature which are only about 6 feet apart. The gas meters have a very small pressure drop across them. Thus the temperature gain is mostly or entirely due to cold gas in an uninsulated pipe passing through a warm space.

If we put in a bias error (B2) due to spatial temperature variation of 3oF into the uncertainty analysis then natural gas temperature goes from an insignificant contributor to one of largest contributors to overall thermal efficiency uncertainty. See Temperature Measurement/QUANTIFICATION OF UNCERTAINTY IN MEASURED PARAMETER section for discussion of B2.

EFFECT OF A THROTTLING VALVE ON THERMAL EFFICIENCY


Test 2.05 was intended to test the theory that throttling a valve between Tin and Tout might improve boiler efficiency by creating friction heat in the piping. The valve between Tin3 and Tin2 was throttled as much as possible during 2.05. Figure 44 shows that there was no noticeable increase in water temperature across the throttled valve. Based on the increase in circulation pump power to overcome the extra pressure drop we expected to see about a 0.25oF increase in temperature from Tin3 to Tin2 with the valve throttled. Instead the data shows only about a 0.02oF increase (it actually drops but drops less than in 2.04 so this is a net increase).

FIGURE 44. AVERAGE WATER TEMPERATURE DURING 2.04 AND 2.05

However, Figure 45 shows a statistically significant increase in thermal and combustion efficiency from 2.04 (valve open) to 2.05 (valve throttled). It is not yet clear if this increase in efficiency can be attributed to the throttled valve or other factor(s). Additional data analysis and/or lab testing is needed. The HP of the circ pump in the test setup is likely too small to make a lab test conclusive without a larger pump.


FIGURE 45. EFFICIENCY AND UNCERTAINTY FOR 2.04 AND 2.05

RECOMMENDATIONS RECOMMENDED CHANGES TO STANDARD 155P

1. Gas Temperature

a. Add gas temperature to Table 2. The resolution and accuracy should be the same as the air temperature thus it can simply be added to the item for that row.

b. Require that gas temperature be measured upstream and within 6 inches of the gas meter and that gas piping be insulated from the temperature sensor to the meter. Standard 155P Appendix A says: Tg = temperature of gas in meter, °F (°C)” but does not provide additional guidance and requirements on measuring gas temperature. What if temperature cannot be measured “in” the meter? This was the case with the meters used in this project. Adding this requirement will mitigate the spatial uncertainty in the natural gas temperature.

2. Sampling Rate

a. Increase the sampling rate requirement for steady state testing to at least 1 sample per minute. This will mitigate the impact of precision error on overall absolute uncertainty. As shown above in the section on “IMPACT OF SAMPLING INTERVAL ON TEST UNCERTAINTY”, going from 15 minute intervals to 1 minute intervals will reduce overall thermal uncertainty from about 1.5% to about 1.0%.


Most test labs will be using a data acquisition system so using a 1 minute or shorter sampling interval is not difficult.

3. Uncertainty Analysis

a. Consider requiring a detailed uncertainty analysis be submitted with the test results. The spreadsheet developed for this research project can be made available to anyone as a starting point.

b. Consider allowing accuracy of some sensors to be higher than the Standard requires if the tester calculates an overall uncertainty that is lower than required by the Standard. This is akin to the AHSRAE Standard 90.1 performance compliance approach instead of the prescriptive compliance approach. This is basically what happened in this research project. The flow meter could not meet the ± 0.25% of hourly rate requirement because the Coriolis meters used for calibrating the mag meter had a stated accuracy of ± 0.3%. But the overall accuracy was better than the standard requires because the water temperature sensors were better than required.

4. Gas and Water Flow Meter Range

a. Consider flow range requirements for flow meters such as, “velocity at the water meter shall be at least 0.5 feet/second and 10% of the meter range”, and “gas meter flow rate may not be below 10% of the maximum reading for the meter”. Accuracy for any flow meter degrades at very low flow and a number on a manufacturer’s cutsheet cannot be relied upon. The Badger meter used in the project, for example, listed an accuracy of ± 0.25%, but clearly was not that accurate at low flow (fortunately, we had the smaller coriolis meters to calibrate the meter at low flow).

5. Gas and Water Flow Meter Accuracy

a. Consider relaxing the accuracy requirement of both meters from 0.25% of hourly rate to 0.4% or 0.5%. This will likely allow more and lower cost metering options and will have neglible impact on overall uncertainty.

6. Sensor Redundancy

a. Consider requiring redundant water meters and/or requiring that test be redone with different meters. For example, if there is a recirc pump at the boiler then a high fire high temp test could be run with 180/140 with a large water meter (recirc pump off) and repeated with the recirc pump on at 180/100 at a smaller water meter.

b. Flow rate cannot be varied at the gas meter but multiple meters could be used in series for single test or parallel for repeated tests.

7. Idling Tests

a. Consider requiring a minimum test duration (e.g. 3 hours) and/or allowing a minimum test period to be substituted where burner on time is variable and cannot easily meet the cycle stability requirements. Accuracy and resolution of the boiler’s internal aquastat and firing controls may make consistent cycle durations difficult. If a boiler cycles frequently then running it for several hours (which could be more than 20 cycles) should be quite accurate on average.


RECOMMENDED FUTURE RESEARCH

MIXING DEVICES Strafication in outlet water temperature was identified as a problem in Phase I (see Phase I report). As a result of Phase I research a mixing verification temperature array was added to Standard 155P. This adds cost and complexity to what is already a significant testing burden. The committee, therefore, is interested in identifying mixing devices that could be required at the boiler outlet in lieu of the mixing verification array. ATS staff and Standard 155 committee members devised the following potential test setup to create stratification and then test devices and pipe velocities that eliminate it. Stratification is created by splitting a pipe in half, welding a plate longitudinally to create an upper and lower chamber within the pipe, welding a plate laterally to cover half of one end of the pipe, and then feeding hot water into the upper chamber and cold water into the lower chamber. The flow streams then come together at the end of the longitudinal plate and remain stratified or mix depending on velocity, fittings, etc. Mixing is verified with two temperature sensors inserted past the branch of a TEE with one sensor very near top of the pipe and the other very near the bottom. Between the split pipe and verification sensors the test setup can accommodate different fittings, including four elbows (Figure 46), straight pipe (Figure 47) and four Tees (Figure 48).

A series of tests would be run with the different fittings, ratios of hot/cold, water temperatures, flow rates, etc. The goal of the testing would be to witness stratification under various conditions and to test a solution that eliminates it under all conditions and that is highly likely to eliminate any potential stratification that might occur during 155P testing. One possible recommendation could be: “between the boiler and Tout there shall be a U arrangement with 4 elbows or 4 tees. Each of the 3 legs of the U shall be at least 2 pipe diameters and shall have a velocity of at least 5 ft/sec.”


FIGURE 46. MIXING TEST SETUP - 4 ELBOWS

FIGURE 47. MIXING TEST SETUP - STRAIGHT PIPE


FIGURE 48. MIXING TEST SETUP - 4 TEES

THERMAL EFFICIENCY UNCERTAINTY There is still more work that could be done to help convince the 155P Committee that thermal efficiency can be consistently measured with reasonable cost and accuracy and to develop new recommendations to improve the standard (e.g. new sensor accuracy requirements or calibration requirements). Additional testing at ATS with some new sensors and including at least one new boiler is advised.

MAG METERS

Perhaps the biggest deficiency with the current test setup is that it only has one magnetic water flow meter which was sized for full fire of the biggest possible boiler the test stand can accommodate. It is clear that any test stand for 155 testing should have multiple flow meters to accommodate multiple size boilers and even multiple flow rates for a single boiler. Therefore, the test stand at ATS should be upgraded to have at least one or two smaller size mag meters in parallel with the existing one (and also in series if not too difficult).

The bypass recirc pump at the boiler should also be fixed so that the flow/ΔT at the flow meter(s) can different from the flow/ΔT at the boiler. A low flow/ high ΔT (e.g. 180/100) at the flow meter could allow a smaller size meter to be used as appropriate.

COST DATA

Cost data should be collected for all sensors used in the test facility and for other possible sensors. Data should also be collected on the cost and accuracy of different calibration options, including both in-house calibration and 3rd party calibration. From this research we will better be able to advise the committee on how to improve the standard.

HIGHER HEATING VALUE (HHV)

The analyses and conclusions in this report could be strengthen by further investigating the HHV data on the PG&E website. For example, the higher frequency samples that are rolled into the published weekly average readings should be available somewhere within PG&E.


We should also do some instantaneous measurements using the chromatagraph available to ATS.

Furthermore, research should be done on the accuracy and cost of HHV options that could be used for typical testing, including:

· Calorimeter

· Gas chromatograph

· Collecting a gas sample with a syringe during a test and having it sent to a lab for analysis.

· Using span gas of a know concentration to calibrate Calorimeter or Gas chromatograph

AMBIENT TEMPERATURE EFFECTS AND NEW TEST PROCEDURES While the focus of the 155P committee is to further reduce the burden of 155P, there are members of the committee who believe that 155P has already been watered down too far and there is a need to establish more comprehensive test procedures. Indeed this research at ATS has provided some glimpses that 155P testing may not be sufficient to adequately characterize how a boiler will operate in a typical commercial application. For example, 155P allows the tester to retune the boiler before every test and thus does not account for the fact that efficiency may degrade in the field when a boiler is tuned at one ambient temperature during start up and operated at other temperatures. Thus one focus of further research would be to characterize the effect of ambient temperature on efficiency and to develop new test methods for possible inclusion in future versions of 155P or other standards. The testing would consist of tuning boilers at one set of room and inlet temperature conditions then testing the boiler at different temperature conditions and different loads.

One outcome of this research might be a new optional test procedure that could be added to the standard for testing ambient temperature effects. It would specify that the boiler is tuned at one temperature then tested at that temperature and at other temperature(s).

Boiler manufacturers recognize that ambient temperature affects performance and some manufacturers have developed advanced control algorithms to account for ambient temperature and optimize performance (e.g. O2 Trim). These are controls that dynamically adjust the air-fuel ratio based on measured temperature or flue gas conditions. Currently, however, 155P does not allow these manufacturers any way to “take credit” for these technologies. A new test procedure for ambient temperature effects would allow them to “take credit” and would encourage manufacturers to include temperature compensation with their controls and to develop new and better techniques for temperature compensation.

DYNAMIC BOILER TESTING None of the 155P tests actually tests the boilers under their own control with a real load. For the steady state tests the firing rate is locked. For the idling tests the boiler is under its own control but there is no load so this gives little indication of how a boiler will operate under non-zero loads. The standard assumes that a boiler serving a load above its minimum firing rate will operate at steady state, i.e. it will not over-fire and cycle off. The supplemental testing done on Unit 3 and field experience indicates that this is not always


the case. Depending on how robust the boiler’s internal controls are and how variable the load is can determine whether or not a boiler cycles above minimum fire. These two factors—controls stability and load variability—affect each other and can cause a boiler system to perform far worse than the 155P tests might indicate. When a boiler cycles off the supply temperature to the load quickly falls which can cause the valves to open. When the boiler cycles back on the valves may not compensate in time and the boiler may have to ramp up. Then when the valves do compensate for the higher water temperature the boiler may have to cycle off. Thus boiler controls instability can cause load instability and vice versa.

New research on boiler internal controls would consist of subjecting boilers under their own control to different load profiles and seeing how the boilers respond to the varying loads. In the same way that new test procedures for ambient temperature effects may expose boilers that do not respond well to ambient temperature, new test procedures for actual load control may expose boilers that do not have good firing control algorithms. Exposing poor firing controls will of course encourage manufacturers to develop better controls.

POSSIBLE DYNAMIC TESTING PROCEDURES

1. Above minimum flow

The load will be adjusted by modulating the boiler pump speed. The tower speed will be fixed at a speed high enough to meet 100% load at the given HWS/R temperatures and outdoor wetbulb (default 100% speed). The mixing valve will maintain the test rig incoming temperature, Ti, at setpoint. Note that the mixing valve control will not be very stable if the boiler firing control is not very stable or the boiler is cycling between low fire and no fire. This is ok as it probably approximates the behavior of coil control valves responding to HWST fluctuations from boiler firing. The mixing valve PID should probably be fairly slow since coil valves will not respond quickly.

2. At minimum flow

The minimum pump speed will correspond to the boiler minimum flow rate. When the pump speed gets to minimum flow the mixing valve will modulate from current position to full bypass, i.e. it will switch from maintaining HWRT to modulating over the range from current position to full bypass (no load).

If the boiler has no minimum flow requirement then there is only one region of control, i.e. only the pump speed is needed to modulate the load. The minimum pump speed is the lowest speed at which the pump will still spin (e.g. 3 Hz). To modulate load below minimum pump speed the pump will cycle off

3. Slow Test – Full Range

a. With the boiler maintaining HWST at setpoint and the mixing valve maintaining Ti at setpoint, and the minimum flow controls active

b. Slowly modulate the load from 100% load (max pump speed) to 0% load over 60 minutes.

c. Max pump speed is the steady state high fire flow rate

d. Wait 5 minutes

e. Shut off the pump (if not off)

f. Wait 10 minutes


g. Turn on the pump and slowly raise the load from 0% to 100% over 60 minutes.

4. Fast Tests – Small Range

The slow test simulates a system with lots of relatively small valves. The fast test simulates a system with relatively few valves where the opening/closing or a single valve has a larger impact on the boiler load.

a. Modulate the pump speed between speeds corresponding to 30% and 40% of the high fire flow rate in cycles of 5 minutes. Note that the mixing valve PID loop may need to be adjusted for faster response. If the range is below the min pump speed then modulate the mixing valve rather than the pump speed.

b. Repeat with other ranges and cycle times, depending on boiler turndown and how the boiler responds to the tests conducted.

5. Mass Effects

Add a large buffer tank (e.g. 100 gallons) to the boiler loop and divert all flow through the tank. Repeat Slow Test and Fast Tests with buffer tank.

SPREADSHEET DEVELOPMENT ATS and Taylor Engineering have developed some very powerful spreadsheet tools for uncertainty analysis and disqualification analysis (in this phase) and results reporting (done in Phase I). These tools could be very useful for boiler manufacturers and others performing 155P testing. However, the tools are not fully debugged or user friendly at this point. They need to be more thoroughly tested, debugged and documented in order to be used by the industry.


APPENDICES BOILER WATER VOLUMETRIC FLOW

VOLUMETRIC FLOW METER MANUFACTURERS SPECIFICATIONS

PRE CALIBRATIONS Flow Standard Boiler Mag Meter Nominal

GPM GPM Dev. Dev.

GPM % 0 0.000 0.012 0.012 5 5.655 5.36 -0.295 -5.21% 10 10.246 9.955 -0.291 -2.84% 15 15.244 15.016 -0.228 -1.49% 20 20.052 19.84 -0.212 -1.06% 40 39.972 39.836 -0.136 -0.34% 60 59.393 59.327 -0.066 -0.11% 72 70.573 70.551 -0.022 -0.03%


POST CALIBRATIONS Flow Standard Boiler Mag Meter Flow Meter

Nominal GPM GPM

Dev. Dev. Standard Size GPM % 0 0.000 0 0.000 CMF50 1/2" 5 5.021 4.681 -0.339 -6.76% CMF50 1/2"

6.9 6.899 6.587 -0.312 -4.52% CMF50 1/2" 7.4 7.356 7.028 -0.328 -4.46% CMF50 1/2" 7.8 7.856 7.492 -0.364 -4.64% CMF50 1/2" 10 9.928 9.622 -0.306 -3.08% CMF50 1/2" 15 14.955 14.662 -0.293 -1.96% CMF100 1" 20 20.111 19.851 -0.260 -1.29% CMF100 1" 22 22.552 22.316 -0.236 -1.05% CMF100 1" 24 24.275 24.023 -0.251 -1.04% CMF100 1" 40 39.896 39.646 -0.250 -0.63% CMF200 1" 60 60.490 60.367 -0.123 -0.20% CMF200 1" 72 70.171 70.084 -0.087 -0.12% CMF200 1"

CORIOLIS FLOW METER

2011 Calibrations

Alden Research Lab Summary Date 7/21/2011

2011 Calibration

Meter CMF 050 CMF 100 CMF 200 CMF 300 Sensor S/N 489554 310890 492019 303561 Transmitter S/N 7152877 1512944 7154522 1512984 Calibration Date 6/13/2011 6/10/11 6/1/11 6/8/11 Max Cal Flow (gpm) 20.25 81.52 250.97 1206.13 Min Cal Flow (gpm) 0.05 4.96 19.44 59.14 Avgas Pulses/lbm 150.2346 24.993 9.990 2.499 Steve Pulses/lb. 0.3980 0.006 0.003 0.001 # Points 19 12 12 19 Avgas Water Temperature (⁰F) 68.4 76.3 74.4 102.8 Avgas Upstream Pressure (psig) 18.1 32.2 32.5 50.4

1" Coriolis Flow Standard Uncertainty


25 gpm 5207.17975 pulses/min

Parameter Units Nominal

Value

Absolute Systematic

Uncert Sensitivity Abs Error

(gpm)

Pulses (10 min) pulses 52071.8 1 0.00048011 0.00048011 Coriolis cal constant pulses/lb. 24.996 0.063849 -0.9992 -0.06380 Water specific volume ft3/lb. 0.016044 3.2088E-06 1558.2 0.00500 time min 10 0.00167 -2.4975 -0.0041625 Drift %

0.10%

0.025

Temp effect gpm

0.00209832

0.00209832 Press effect gpm

0.0028125

0.0028125

Qa

25.00

0.069 gpm

0.28%

K avg 24.996

10 - 79 gpm

K std dev 0.051

n 12

S_K mean 0.014722

B_K 0.20%

0.049992 pulses/lb.

t 2.200985

U_K 0.063849 pulses/lb.

U = t*sqrt[(B/2)^2+S^2]

0.255%

TEMPERATURE STANDARD


800 CFH NATURAL GAS METER CALIBRATION REPORT


1500 CFH METER CALIBRATION REPORT

Boiler Research Project - ASHRAE Standard 155P – Phase II Boiler Research Testing_12...Dec 21,...

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