Improving Methane Emission Estimates for Natural Gas ... · Distribution Companies Phase II – PE Pipes Prepared For: Operations Technology Development, OTD Prepared By: Khalid Farrag,

OTD-14/0001

Improving Methane Emission

Estimates for Natural Gas

Distribution Companies,

Phase II – PE Pipes

Prepared by:

Gas Technology Institute

Des Plaines, Illinois

November 2013

GTI REPORT NUMBER 21044 OTD PROJECT NUMBER 7.10.c

Improving Methane Emission Estimates for Natural Gas Distribution Companies Phase II – PE Pipes Prepared For: Operations Technology Development, OTD

Prepared By: Khalid Farrag, Ph.D., P.E., PMP 847-768-0803 [email protected] GTI Project Manager: Kristine Wiley 847-768-0910 [email protected]

Gas Technology Institute 1700 S. Mount Prospect Rd. Des Plaines, Illinois 60018 www.gastechnology.org November, 2013

FINAL REPORT

Page i

Legal Notice

This information was prepared by Gas Technology Institute (“GTI”) for the Operation Technology Development (OTD). Neither GTI, the members of GTI, OTD, nor any person acting on behalf of any of them:

a. Makes any warranty or representation, express or implied with respect to the accuracy, completeness, or usefulness of the information contained in this report, or that the use of any information, apparatus, method, or process disclosed in this report may not infringe privately‐owned rights. Inasmuch as this project is experimental in nature, the technical information, results, or conclusions cannot be predicted. Conclusions and analysis of results by GTI represent GTI's opinion based on inferences from measurements and empirical relationships, which inferences and assumptions are not infallible, and with respect to which competent specialists may differ.

b. Assumes any liability with respect to the use of, or for any and all damages resulting from the use of, any information, apparatus, method, or process disclosed in this report; any other use of, or reliance on, this report by any third party is at the third party's sole risk.

c. The results within this report relate only to the items tested.

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Improving Methane Emission Estimates for Natural Gas Distribution Companies

Phase II – PE Pipes

Project Team

Khalid Farrag, Ph.D., P.E., PMP Principal Investigator, Gas Technology Institute Phone: 847-768-0803 [email protected] Kristine Wiley, Project Manager, Gas Technology Institute Phone: 847-768-0910 [email protected] Matt Harrison, P.E. Project Consultant, URS Corporation, Austin, TX Phone: 512-694-0572 [email protected]

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Table of Contents

Page

Table of Contents ......................................................................................................................... iii

Table of Figures ............................................................................................................................ v

List of Tables ............................................................................................................................... vii

Executive Summary ...................................................................................................................... 8

Introduction ................................................................................................................................. 10

Chapter 1 - Summary of Existing Emission Estimates ................................................................ 13

A) The GRI-EPA Study 13

B) EPA Emission Factors Estimates for Distribution System 15

Chapter 2 - Surface Measurements of Methane Emissions ....................................................... 17

A) Introduction 17

B) Measurements Procedure 18

Chapter 3 - Evaluation of the Hi-Flow Device Measurements .................................................... 22

A) Introduction 22

B) Tests on Aboveground Leaking Pipes 22

C) Tests on Belowground Leaking Pipes 25

Chapter 4 - Factors Affecting Gas Leak Measurements ............................................................. 28

A) Introduction 28

B) Pipe Operating Pressure 28

C) Pipe Age 28

D) Soil Type 29

E) Parametric Analysis of Gas Leak Measurements 30

F) Temperature Effect 33

G) Selection of the Utility Sites for Field Tests 34

Chapter 5 - Field Measurements at Utility Sites .......................................................................... 37

A) Introduction 37

B) Emission tests at Utility Site [A] 38

C) Emission tests at Utility Site [B] 40

D) Emission tests at Utility Site [C] 42

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E) Emission tests at Sites [D] 44

F) Emission tests at Sites [E] 44

G) Emission tests at Testing Facility 44

H) Summary 47

Chapter 6 - Results of the Field Testing Program ....................................................................... 48

Chapter 7 - Emission Factors from Belowground PE Leaks ....................................................... 51

A) Emission Factor of PE Mains 51

B) Comparison with the GRI-1992 Emission Factor 53

Chapter 8 - Activity Data and Total Emissions ............................................................................ 55

A) Current Estimates of the Activity Data 55

B) Incorporating the Emission Factor with the Activity Data 56

C) Total Emissions Estimates 57

References .................................................................................................................................. 59

List of Acronyms ......................................................................................................................... 60

English to Metric Unites Conversions ......................................................................................... 61

Page v

Table of Figures

Page

Figure 1 - Layout of the GTI multi-phase methane emissions programs .................................... 10

Figure 2 - Schematic of the GRI-EPA testing procedure (1) ....................................................... 13

Figure 3 - View of the Hi Flow Sampler device ........................................................................... 17

Figure 4 - Capturing gas leak area for rate measurements ........................................................ 18

Figure 5 – The CGM meter used to identify the leak area .......................................................... 19

Figure 6 - Schematic of surface measurements with the Hi-Flow device ................................... 19

Figure 7 - Measurements belowground leak rates ...................................................................... 20

Figure 8 - View of the LFE and flow meters devices ................................................................... 21

Figure 9 - Laboratory measurements of the gas flow rates ........................................................ 23

Figure 10 - Measurements of the Hi-Flow in Laboratory tests .................................................... 23

Figure 11 - Aboveground measurements of leak rate at test facility ........................................... 24

Figure 12 - Measurements of the Hi-Flow in aboveground pipe ................................................. 24

Figure 13 - Locating the leak area in the test section ................................................................. 26

Figure 14 - View of the covered leakage area ............................................................................ 26

Figure 15 - The Hi-Flow and meter flow rates in belowground tests ........................................... 27

Figure 16 - Plot of the flow rate versus line pressure for steel mains (1) .................................... 29

Figure 17 - Plot of the flow rate versus pipe age for cast iron mains (1) ..................................... 29

Figure 18 - Plot of leak rate versus soil clay content (1) ............................................................. 30

Figure 19 - Response Surface of the effect of pressure and soil on the Hi-Flow measurements .................................................................................................................................................... 31

Figure 20 - Response surface model showing the effect of pressure and flow rates on the Hi- Flow measurements .................................................................................................................... 32

Figure 21 - The finite element mesh used in the temperature analysis ...................................... 33

Figure 22 - Displacements around the pipe hole at max temperature change ........................... 34

Figure 23 - Field tests at utility sites ............................................................................................ 35

Figure 24 - Comparison of mains and service data in sites and top-100 utilities ........................ 36

Figure 25 - Test 1 at the Utility Site A ......................................................................................... 38

Figure 26 - Test 2 at Utility Site A ............................................................................................... 39

Figure 27 - Test 3 at utility site A ................................................................................................ 39

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Figure 28 - Test 1 at the Utility Site B ......................................................................................... 40



Figure 31 - Test 1A at the Utility Site C ....................................................................................... 42

Figure 32 - Test 1B at the Utility Site C ....................................................................................... 43

Figure 33 - Test 2 at the Utility Site C ......................................................................................... 43

Figure 34 - Test 3 at the Utility Site C ......................................................................................... 44

Figure 35 - Test 1 at the Utility Site D ......................................................................................... 45




Figure 39 - Flow Rate Measurements at the GTI field testing facility.......................................... 47

Figure 40 - Variability of the measurements with the pipe leak rates ......................................... 49

Figure 41 - Correlation between the Hi-Flow measurements and pipe leak rates ...................... 50

Figure 42 - Distribution of gas concentration in a typical utility record ........................................ 51

Figure 43 - Distribution of gas concentration readings in the field tests ..................................... 52

Figure 44 - Modeling the input-output relationships in the emission estimates .......................... 54

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List of Tables

Page

Table 1 - Reported Leak Rates of PE Mains in Various Sources 9

Table 2 - Summary of Measurements of Leak Rates (1) 14

Table 3 - Methane Emission Factors for Distribution Pipelines (1) 15

Table 4 - Default Methane Emission Factors for Distributions (Table W-7) (2) 15

Table 5 - Emissions for the Natural Gas Distribution Systems (3) 16

Table 6 - Calculated precision from the repeatability test results 25

Table 7 - Testing Parameters at the Controlled Leak Tests 31

Table 8 - Results of the Factorial Analysis of the Leak Tests 31

Table 9 - Ranges of Parameters Used in the Parametrical Study 32

Table 10 - Change of the hole-size with temp increase from 30oF to 90oF 34

Table 11 - Summary of Leak Classification and Selected Examples (10) 36

Table 12 - List of the Emissions Field Test 37

Table 13 - Flow Rate Measurements at the Test Sites 48

Table 14 - Descriptive Statistics of the Leak Rates for Emission Factor 49

Table 15 - Statistics of the Gas Concentrations in Utility Records and Field Tests 53

Table 16 - Methane Emission Factor Distribution PE Mains 53

Table 17 - Descriptive Statistics of the GRI-1996 Data 54

Table 18 - Activity Data for Distribution Pipelines (5) 56

Table 19 - Methane Emissions for Gas Distribution (in Mg), 2008 (3) 56

Table 20 - Comparison of the Emission Factor Results 57

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Executive Summary

A field testing program was performed to: (a) Evaluate gas leak rates from belowground pipelines, (b) provide a simplified procedure that can be used to monitor pipeline leaks from surface measurements, and (c) update the methane emission estimates for the main lines in the distribution system.

The new procedure utilizes the Hi-Flow Sampler device to measure leak rates at the surface. The field measurements consisted of identifying the leakage areas using the standard utilities leak-detection tools and using the Hi-Flow device in measuring gas flow rates in the covered leak areas at the surface.

The utility test sites were selected as randomly as possible to obtain measurements representative of the population distribution of leak records and to reduce the bias resulting from the sites selection. A total of five utilities participated in the PE field tests and the sites were selected from the locations identified in the leak records of the participating utilities. The field measurements included the following two procedures:

Aboveground measurements of methane emission rates using a surface enclosure of the leak area and the Hi-Flow device. A total of 30 tests at the utility sites and field testing facility were performed using this procedure.

Measurements of the gas flow rate of the belowground leak in an isolated segment of the pipe. A total of 21 tests were performed in the above sites with these measurements. This procedure is similar to the earlier GRI-EPA procedure which was used to establish current emission factors.

The results from the two above procedures validated the Hi-Flow surface measurements and provided an updated estimate of the Emission Factor (EF) for the PE mains.

Most of the PE leaks at the utility sites were characterized by low gas concentration readings at the surface and low emission rate measurements. The leak records of the PE mains had a small size of records with higher leaks and a weighted function was introduced to the measurements of the utility sites and field testing facility. The combined field measurements provided a representative distribution of the full range of the gas concentrations in the utility records.

The results of the testing program provided an Emission Factor estimate of 3.72 scf/leak-hour for the PE mains. This EF is lower than the earlier GRI and EPA estimates. Table 1 shows the various reported leak rates and emission factors in these sources. Various unites were used by these sources and the table shows the equivalent EF values from the current study in these units.

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Table 1 ‐ Reported Leak Rates of PE Mains in Various Sources

Reported Unites scf/leak-hour scf/mile-hour Mscf/mile-year

This Study 3.72 0.26 2.28

GRI-EPA , 1996 (1) 12.45 - -

EPA, Subpart W, 2010 (2) - 1.13 -

EPA, Emissions Inventory, 2008 (3) - - 10

The GRI-EPA study (1996) provided an EF estimate of 12.45 scf/leak-hour for the PE mains. This estimate was the average value of a smaller sample of six data points, with one large data point that skewed the average emission rate. The selection of the ‘Mean’ to represent the skewed data resulted in a higher estimate which did not account for the log-normal distribution of the PE leaks.

The EPA estimates of the methane emissions from natural gas system are based on the GRI-1996 study. However, the EPA inventory is presented per the number of miles for each pipe type, and the total emission factors are in the units of Mscf/mile-year.

The EF estimate in this study was converted to the mileage-base in the table from an average estimated rate of about 0.07 leaks per mile for the top 100 utilities with the largest services. This rate was estimated from the data records of the DOT annual reports which provide estimates of the leak repairs of pipelines (4).

Finally, in addition to a national estimate based on the pipes mileage for the EPA inventory, local distribution companies may also estimate their total emissions based on the number of leaks in their reporting system. This ‘utility-based’ emissions use Activity Data which already exists in their leak and repair records and can be periodically updated for more accurate estimates. The use of number of leaks as the activity data also provides the following advantages:

Takes into account aggressive leak repair plans which has direct impact on reducing the number of leaks, and consequently, the total emission,

Reflects improvements due to rehabilitation (such as using liners to reduce leaks in mains),

Allows for incorporating recent advances in leak detection methods and practices, thus resulting in a more accurate number of leaks.

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Introduction

Due to the growing concern over climate change and the reduction of greenhouse gas (GHG), local distribution companies, research organizations, and the EPA(*) have recognized the need to update the methane emissions estimates from the gas distribution operations. A multi-phase project was initiated by GTI to update the methane emission estimates for natural gas distribution pipelines and to provide a simplified field procedure that can be used by the LDC companies to monitor their local emissions estimates. A layout of the program is shown in Figure 1 and its overall objectives are:

Perform a critical review and assessment of current methodologies.

Develop and evaluate an alternative technical approach and field procedure for estimating methane emissions from belowground pipeline leaks.

Perform field testing and analysis to establish new emission factors from the new procedure.

Integrate the methodology with current LDC’s activity data for implementation into the GHG emissions estimates.

Figure 1 ‐ Layout of the GTI multi‐phase methane emissions programs

(*) A list of acronyms is provided at the end of the report.

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The project focuses on the methane emissions from belowground pipeline leaks due to their large contribution to total emissions for the LDCs and the need to provide updated and accurate emission estimates; thus resulting in an opportunity for emissions management and reductions.

As shown in Figure 1, the research project consists of the following phases:

Phase-I: Technical approach and methodology assessment,

Phase-II: Field measurements of emission factors of PE pipelines,

Phase-III: Field measurements of emission factors of unprotected steel and cast iron pipelines,

Phase-IV: Deployment and Implementation into LDCs practices.

Phase-I of the research project assessed the previous methodologies used in estimating leak rates from belowground pipelines and proposed a technical approach for surface measurements of the flow rates at leak sites. Aboveground measurements were performed in controlled tests where gas leak areas were covered and the leak rates were measured using the Hi-Flow Sampler device. The results of these tests demonstrated the applicability of using the Hi-Flow device to measure gas flow rates at the surface and provided a framework for the tests at utility sites in the subsequent phases.

This report presents the testing program and results of Phase-II of the project. It focused on determining the emission rates from belowground PE pipes. The measurements were performed at sites selected from the utilities leak records without consideration if the leaking pipes are planned for replacement, repairs, or monitoring. The field measurements included the following:

(a) Aboveground measurement of methane emission rates using a surface enclosure of the leak area and the Hi-Flow device, and

(b) Measurement of the gas flow rate of the belowground leak source in an isolated segment of the pipe. This measurement is similar to the earlier GRI-EPA procedure which was used to establish current emission factors (1).

The advantage of performing both measurements is to correlate aboveground emissions to the belowground gas flow rates at the leak sources; thus evaluating the effect of the various parameters which influence emissions.

The results of the surface measurements at the utility sites provided an updated estimate of the Emission Factor for the PE pipes and validated the results with the belowground measurements. Complimentary tests at the GTI field testing facility were also performed to evaluate the emission factors at higher leak rates than the ones encountered at the utility sites. The incorporation of these additional results into the Emission Factor estimates provided a more conservative estimate which covers a wider range of PE leaks as observed in the utilities leak records.

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Chapter 1 of the report presents a review of the current estimates of the emission factors. An overview of the procedure of surface measurements using the Hi-Flow device is presented in Chapter 2.

An evaluation of the Hi-Flow measurements and the factors affecting surface measurements of methane emissions are presented in chapters 3 and 4, respectively. The field tests performed at the utility sites and the GTI field testing facility are presented in chapter 5 and the results of these tests are presented in Chapter 6.

Chapter 7 presents the estimation of the PE Emission Factor from the test results and Chapter 8 presents an overview of the procedure to estimate the Activity Data (AD) and calculate the total emissions from the belowground PE pipes.

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Chapter 1 - Summary of Existing Emission Estimates

A) The GRI-EPA Study

The 1996 GRI-EPA study serves as the primary source of information for methane emissions from the natural gas industry. The study determined the emission estimates for the natural gas infrastructure from the activity and emission factors as represented by the following equation:

Total Emissions = (Emission factor x Activity Factor) [1]

Where,

Emission Factor = the amount of methane released by an emitting entity,

Activity Factor = the total population of the emitting entity.

For belowground distribution mains and services, leak measurements were collected by the participating companies using a standardized testing protocol (1). Because the emission factors are variable in nature, subsets of the total emissions were defined for the emission and activity factors based on pipeline parameters.

The parameters that had the most influence on the estimation of the emission factors for belowground pipes were the pipe use (i.e., main versus service) and pipe material and the GRI-1996 study (5) quantified the activity data based on these two parameters.

The emission factors were determined by isolating a known underground leak. The line was shut off at both sides of the leak without disturbing the soil around the leak source. Gas was supplied to the isolated pipe section, and measurements were taken using laminar flow elements to estimate the gas flow rates (i.e., volume of gas leak per unit time). Figure 2 shows a schematic of the procedure used to estimate the emission factors.

Figure 2 ‐ Schematic of the GRI‐EPA testing procedure (1)

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The leak rates were calculated from Table 2 to produce the annual average rates. The units of Emission Factors for mains and services were in scf/leak-year except for the cast iron pipes which was in scf/mile-year.

Table 3 shows the calculated emission factors for the main and service pipes. For the PE mains, the gas leak rate of 12.45 scf/leak-hour was multiplied by 8,760 hours/year and by the methane content in the gas composition (average 93.4 percent) to produce an annual average methane leak rate of 101,897 scf/leak-year.

The methane Emission Factors in Table 3 were calculated after subtracting the amount retained in soil due to soil oxidation. The soil oxidation rates were estimated from a separate GRI study to account for the oxidation of methane (CH4) from soil microbes (6). The results of the study have demonstrated that a large fraction of leaked methane can be oxidized when the leak rates are small; and the oxidation fraction decreased with the increase in the leakage rate. Other factors such as soil type, soil moisture, and temperature also affect the rate of methane oxidation in the soil.

The oxidation reduction for the PE service lines was estimated to be about 21.2 percent due to the small leaks in this type of pipes. However, the oxidation rate for the PE mains was estimated to be only 2 percent. This low percentage was selected mainly due to the high leak estimate given to the PE mains in the GRI-1996 report.

Table 2 ‐ Summary of Measurements of Leak Rates (1)

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Table 3 ‐ Methane Emission Factors for Distribution Pipelines (1)

B) EPA Emission Factors Estimates for Distribution System

Similar to the GRI study, the methane emission estimates are calculated by multiplying the Emission Factors by the Activity Data. The Activity Data used by the EPA are the number of mileage for the specified pipeline type, as in the following equation:

Total Emissions = (Emission Factor x Activity Data) [2]

The EPA Mandatory Greenhouse Reporting (2) requires that natural gas distribution facilities use the appropriate default population emission factors for fugitive emissions (Table 4).

Table 4 ‐ Default Methane Emission Factors for Distributions (Table W‐7) (2)

Note: - For Mains, Emission Factor is in scf/mile-hour

- For Services, Emission Factor is in scf/service-hour

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The comparison between the Emission Factor for plastic pipes in Table 4 (1.13 scf/mile-hour) and the GRI-EPA Emisson Factor of 12.45 scf/leak-hour in Table 2 shows a conversion factor of about 0.09 leaks/mile.

The EPA utilized the results of the GRI study, and periodically updates their factors in their annual inventory of greenhouse emissions (3). In the EPA annual inventory records, emission factors are presented in units of methane volume (Mscf) per mile of pipe for the gas mains. These factors are multiplied by the Activity Data to estimate the total emissions as shown in Table 5 .

Table 5 ‐ Emissions for the Natural Gas Distribution Systems (3)

Mains Activity Data

(miles) Emission Factor (Mscf/mile‐yr)

Emissions (Mg)

Cast Iron Unprotected Steel Protected Steel Plastic

36,462 69,374 479,502 603,377

239 110 3 10

167,628 147,229 28,324 115,164

Services Activity Data (services)

Emission Factor (Mscf/service)

Emissions (Mg)

Unprotected Steel Protected Steel Plastic Copper

5,388,623 15,456,866 41,573,069 1,140,738

2 0.2 0.01 0.3

176,514 52,543 7,445 5,588

‐ (From Table A‐121, 2008 EPA Adjusted Values) ‐ Mscf = Thousand standard cubic feet ‐ Mg = Mass emissions at standard conditions in metric tons.

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Chapter 2 - Surface Measurements of Methane Emissions

A) Introduction

Similar to the EPA emissions calculations in Equation [2], the new methodology determines the total emissions from the multiplication of the Emission Factors by the Activity Data. The new methodology obtains the Emission Factors of distribution pipelines from the surface measurements of the gas leak rates (in scf/leak-hour). These surface measurements provide actual ‘in-air’ methane emission rates without the need to excavate the leak source and estimate the amount retained in the soil due to oxidation.

Phase-I of the research project established the validity of this approach at utilities testing facilities. The gas leak rates from the surface measurements were validated in controlled leak tests using the Hi-Flow Sampler device. The Hi-Flow device is a portable device that provides real time measurements of gas flow rate and concentration in a captured enclosure (Figure 3).

The testing procedure of Phase-I consisted of introducing leaks in belowground pipes, measuring the surface leak using a cover and a Hi-Flow device as shown in Figure 4 and correlating the measurements with the applied flow rates.

Figure 3 ‐ View of the Hi Flow Sampler device

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Figure 4 ‐ Capturing gas leak area for rate measurements

B) Measurements Procedure

The field tests in Phase-II were performed at utility sites and consisted of performing the measurements as follows:

1. Identify the Leak Area

a) Identify the leak area at the surface from a known leak source: Gas distribution operators use leak detection procedures to locate and classify leaks for repair. To identify a leak in a section of pipe, a portable hydrocarbon analyzer or flame ionization detector (FID) is typically used to screen immediately above the ground while walking the pipeline. Any excursions above the background level (typically above 3-5 ppm) may indicate a nearby leak.

b) The leak is pinpointed by boring holes on each side of the pipe for determining the point of maximum leak concentration. To avoid disturbing the soil immediately surrounding the leak source, the depth of the bar-holes was specified not to exceed approximately 12 inches from the surface. The gas concentration in each bar-hole was measured, with the point of highest concentration typically being the most probable location for the leak.

c) Once the leak was centered, the perimeter of the leak area is determined. The area was mapped using a Combustible Gas Monitor (CGM). The CGM readings, shown in Figure 5, were used to identify the covered area for the Hi-Flow measurements.

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Figure 5 – The CGM meter used to identify the leak area

2. Surface Measurements of the Leak Rate

a) The aboveground measurements of the leak rates were performed by enclosing the leak area with a cover and measuring the methane leak rate using the Hi-Flow device. A schematic of the surface measurements is shown in Figure 6.

b) Various areas of covers were used with an average size of 4 ft wide by 8 ft long. The cover has an opening at the top center to connect to the Hi-Flow device as shown in Figure 4. Sand bags were usually placed on top of the cover perimeter to reduce possible air/methane intrusion or loss from the covered area, which may affect the flow rate measurements.

c) When the identified leak area was larger than the cover, the area was divided in a grid pattern to avoid overlap of the measurements and the total leak rate was the sum of the individual measurements in each area of the grid.

Figure 6 ‐ Schematic of surface measurements with the Hi‐Flow device

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3. Measurements of the Leak Rate in Isolated Pipe Section

(a) At the completion of the surface measurements, the gas flow rate of the belowground leak was measured in an isolated segment of the pipe. This measurement is similar to the earlier GRI-1996 procedure which was used to establish current emission factors.

(b) The pipeline was excavated at two locations at a distance about 15-20 ft at each side of the leak source. The excavations were sufficiently far from the leak source so that soil condition is not disturbed in the leak area.

(c) The pipe was isolated in each excavated section. Most of the pipes were cut and capped in the test sites. Service lines in the isolated segment were also disconnected.

(d) Gas was introduced in the isolated segment at the same operating pressure of the line. The gas flow rate is monitored using flow meters and Laminar Flow Elements (LFE). A schematic diagram of the flow measurements in the isolated section is in Figure 7.

(e) The measurements of gas flow in the isolated segment represent the flow rate from the leak source. A view of the flow meter and LFE devices used in the measurements are shown in Figure 8.

Figure 7 ‐ Measurements belowground leak rates

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Figure 8 ‐ View of the LFE and flow meters devices

The leak rate measurements from the isolated belowground pipes were correlated with the Hi-Flow readings to validate the surface measurements results. The correlation provided a better estimate of leak rates and allowed for performing lager sets of tests at the surface without the need for excavating the pipes, isolating the lines , and disrupting the services.

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Chapter 3 - Evaluation of the Hi-Flow Device Measurements

A) Introduction

The Hi-Flow Sampler device measures the leak rate by sampling at a high flow rate up to 10 scf/min to capture all the leaking gas along with a certain amount of surrounding air. By measuring the flow rate of the sample with the natural gas concentration, the gas leak rate from the source is calculated as:

Leak rate = Flow x (Gas sample – Gas background) / 100 [3]

Where, Flow = sample flow rate (scf/min),

Gas sample = concentration of gas from leak sources (%), and

Gas background = background gas concentration (%).

The minimum methane sensor reading is 0.01 scf/min and the device accuracy as provided from the manufacturer is ±5% of the reading.

The inherit precision of the Hi-Flow device was evaluated by monitoring the repeatability of the results in aboveground leak tests under various applied pressures and flow rates. The tests were performed in controlled lab conditions at GTI and at a gas utility testing facility.

Measurements of leak rates of belowground pipes were then performed at utility testing facilities to establish the procedure for capturing and monitoring gas emissions from belowground pipes and to correlate the surface measurements with the leak rates applied through the gas meters.

These tests were performed in Phase-I of the project (7) and the following sections provide a summary of the results.

B) Tests on Aboveground Leaking Pipes

These tests were performed at the GTI lab and consisted of connecting the Hi-Flow device to a natural gas supply and a calibrated gas meter to control and monitor the gas flow (Figure 9). The gas flow was supplied at a constant pressure with low rates from 0.1 to 0.6 scf/min. The correlation between the device measurements and the applied flow rates is shown in Figure 10.

Tests at the gas utility testing facility were also performed by measuring the leak rates in PE pipes placed aboveground as shown in Figure 11. The tests were performed in 2-inch PE pipes with 1/8‐inch and 1/16‐inch holes and at various gas pressures from 0.25 psig to 20 psig. The gas flow was supplied at higher rates up to 9.5 scf/min and the correlation between the Hi-Flow device measurements and the applied flow rates are shown in Figure 12.

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Figure 9 ‐ Laboratory measurements of the gas flow rates

Figure 10 ‐ Measurements of the Hi‐Flow in Laboratory tests

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Figure 11 ‐ Aboveground measurements of leak rate at test facility

Figure 12 ‐ Measurements of the Hi‐Flow in aboveground pipe

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The results in the previous figure show a high correlation between the Hi-flow device measurements and the applied flow rates in aboveground tests. The repeatability of the results was evaluated using the ‘Range and Average’ method under multiple testing conditions (i.e., various pressures and flow rates). The repeatability of the measurements was calculated as:

Repeatability = .

Where, is the average of the readings of all the conditions and is a parameter depends on the number of the trials (i.e., average of 3 repetitions of measurements). The repeatability values varied with the flow rates as shown in Table 6. The results show that a difference between two repetitive results below the value of 7.2 percent will be likely due to the inherit precision of the device.

Table 6 ‐ Calculated precision from the repeatability test results

Range of flow rates (cfm)

Repeatability value (cfm)

Inherit Precision (%)

0.2 – 0.5 0.3 – 2.3

0.028 0.071

7.52 6.83

Average 7.2

C) Tests on Belowground Leaking Pipes

The correlation between the Hi-Flow measurements and the applied flow rates were performed on leaking belowground PE pipes in the utility testing facility. The PE pipes were 2 inches in diameter and were placed at depth of about 2.5 ft. The trenches were backfilled with granular and silty-sand soils. Gas pressures from 2 to 20 psig were applied in the pipes and the leaks were introduced through 1/8‐inch and 1/16‐inch holes.

The testing procedure consisted of identifying the leak area using portable gas surveyors (Figure 13). A cover was placed to capture the gas leak at the surface as shown in Figure 14. Repetitive measurements were taken using the Hi-Flow device and correlated to the gas flow rates as measured in the gas meters. The gas flow readings from the meters were multiplied by 94% to account for the average methane content in the natural gas system.

The correlation between the Hi-Flow measurements and the gas flow in the belowground pipes is shown in Figure 15 and the figure shows a high correlation (r2 = 0.98). The Hi-flow device measurements were lower and averaged about 0.92 of the meter readings. This is mainly due to several factors; including (a) the inherit precisions of both devices, (b) a portion of the gas is trapped belowground and does not reach the surfaces, and (c) the efficiency of the cover used to capture all the gas flow at the leaking area.

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Figure 13 ‐ Locating the leak area in the test section

Figure 14 ‐ View of the covered leakage area

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Figure 15 ‐ The Hi‐Flow and meter flow rates in belowground tests

As shown from the above results, the accuracy of the surface measurements depends on the precisions of the devices used in the calibration tests. The calibration tests performed at the utility testing facility utilized gas meters, which also have their inherit-precision issues. Accordingly, the gas meters were calibrated to ensure their precision and were temperature and pressure-compensated.

Human error in counting the rotations of the gas meters also affects the accurate measurements of flow rates. Alternatively, the laminar flow elements (LFE) device was used at the utility sites to provide more accurate and stable measurements, especially at the low flow rates encountered in the plastic pipe leaks.

In order to reduce the sampling bias resulting from having systematic under-representation (or over-representation) of parts of the population, random sampling was planned in the selection of the test sites. Furthermore, several factors which affect the gas flow from leaking pipes were investigated to properly represent the variability of these factors in the testing program. The following chapter presents further analysis of these factors.

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Chapter 4 - Factors Affecting Gas Leak Measurements

A) Introduction

Many factors which influence natural gas leak rates were identified in the previous GRI-1996 study (1). The 1996 GRI-EPA study established the test matrix based on the following primary variables:

- Pipe use: mains versus service lines,

- Pipe material, and

- Pipe age.

In order to account for the effect of pipe material and use, the utility pipes were stratified based on their types. The current Phase-II of this project focused on the emissions from PE pipes and the factors that may potentially influence their leak rate measurements include the following:

- Leak detection practices and repair programs,

- Pipe operating pressure,

- Pipe age,

- Soil characteristics.

The following sections present a review of these parameters and their effect on the leak rate measurements.

B) Pipe Operating Pressure

The results of the GRI analysis in Figure 16 show the plot of the leak data versus the pipe operating pressure. The results show that the data were scattered, with a correlation coefficient of 0.46. This coefficient was considered marginal, which supported classifying this relationship as weak or inconclusive.

The results in the figure were for a range of operating pressures from 15 to 55 psig. For plastic pipe mains, smaller variations of line pressures are more common (i.e., with operating pressures in PE mains ranging from 50 to 60 psig). Further evaluation of the effect of the operating pressure is presented later in this chapter.

C) Pipe Age

The results of the GRI-1996 analysis showed that pipe age was not found to affect the gas leak rates. The GRI data in Figure 17 shows the leak data versus the pipe age in cast iron mains since this pipe type provided a large sample of pipes with high age variations.

The pipe ages were not available in the utility field tests and no further evaluation of pipe age was performed in this study.

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Figure 16 ‐ Plot of the flow rate versus line pressure for steel mains (1)

Figure 17 ‐ Plot of the flow rate versus pipe age for cast iron mains (1)

D) Soil Type

Figure 18 shows the service lines leak data from the GRI study versus the soil clay content (1). The scatter in the results shows that the effect of clay content in the soil is insignificant. However the reported analysis stated that the sample size was not large enough to provide dependable information for any of the pipe materials.

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Figure 18 ‐ Plot of leak rate versus soil clay content (1)

E) Parametric Analysis of Gas Leak Measurements

The above results did not provide conclusive correlations between soil type, leak flow size, and operating pressure with the surface emission rates. Further analysis was performed in the current study to evaluate the effect of these parameters. The analysis was performed on the results of the tests performed at the testing facilities. These tests were performed in three soil types, namely, granular and silty soil at the utility testing facility and clay soils at the GTI site. The tests were performed in 2-inch diameter PE pipes at various operating pressures and leak sizes. Table 7 shows the parameters used in the analysis.

The Analysis of Variant (ANOVA) was performed to evaluate the interacting effects of the selected parameters and the results are shown in Table 8. The p-values less than 0.005 in the table indicate that the model terms are significant, with low chance that they have occurred due to noise.

The results show that the soil type (A) is not a significant term, while the line pressure (B), the hole-size (C), and their multiplication (BC) are significant terms which affect the surface emission rate. The results are also displayed graphically in Figure 19. The figure shows the 3-D predicted response surface of the Hi-Flow measurements with the variations of the soil types and line pressures. The figure displays the significant affect of line pressure.

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Table 7 ‐ Testing Parameters at the Controlled Leak Tests

Table 8 ‐ Results of the Factorial Analysis of the Leak Tests

Figure 19 ‐ Response Surface of the effect of pressure and soil on the Hi‐Flow measurements

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Further evaluation was performed on the relationship between the size of the leak (represented by the belowground flow rate measurement) and the Hi-Flow surface measurements. Table 9 shows the ranges of the parameters used in the parametric study. Similar to the previous results in Figure 19, soil type did not have a significant effect on the leak measurements. The 3-D response surface of the Hi-Flow measurements for the applied ranges of gas flow and operating pressures are shown in Figure 20. The figure shows the combined effect of pressure and belowground flow rate on the surface measurements. The changes of the surface emission rates are not significant at low pressures and leak sizes; however, they become highly significant with the increase in these parameters.

Table 9 ‐ Ranges of Parameters Used in the Parametrical Study

Figure 20 ‐ Response surface model showing the effect of pressure and flow rates on the Hi‐ Flow measurements

g3.95

0.01

X1 = A: FlowX2 = B: Pressure

Actual FactorC: Soil = 2.00

0.25

5.19

10.13

15.06

20.00

0.010

0.757

1.505

2.252

3.000

-0.5

0

0.5

1

1.5

2

2.5

Hi-

Flo

w

A: Flow B: Pressure

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F) Temperature Effect

Seasonal changes in temperature can affect the gas flow from belowground pipes and the accuracy of the devices used in the flow rate measurements. In general, temperature affects the readings at the gas meter. For every 5oF, gas volume changes about 1 percent (8). Meters

are commonly calibrated at 60oF and in Cold weather, gas volume is lower. In the experimental tests at the testing facilities, the temperature effect was addressed by using temperature-compensated commercial gas meters. In the measurements at the utility sites, the effect of temperature is incorporated in the laminar flow calculations used in the LFE elements.

In general, soil has low thermal conductivity. However, plastic pipes have relatively high thermal expansion (4-7x10-5 inch/inch/oF) and the hole-size may change with the changes in temperature. This effect was evaluated in an analytical investigation of the changes of a typical hole-size in a PE pipe.

The finite element program (COMSOL) was used to determine the changes of a hole-size due to temperature changes from 30oF to 90oF around the pipe. The analysis was performed on a 1/8-inch hole in a 2-inch plastic pipe. Figure 21 shows the generated mesh used in the finite element analysis. Various pipe lengths were used in the analysis to determine the free length of the pipe which has no boundary effect on the deformation of the hole. In the analysis, the deformations were calculated while neglecting the effect of soil resistance around the pipe.

Figure 21 ‐ The finite element mesh used in the temperature analysis

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The results of the deformations around the pipe are shown in Figure 22. The displacement profile was used to calculate the changes of the hole-size due to the temperature change for a pipe length of 6 ft. The results in Table 10 show a net decrease of 0.71 percent with the temperature increase, which is considered a negligible change in the gas flow rate.

Figure 22 ‐ Displacements around the pipe hole at max temperature change

Table 10 ‐ Change of the hole‐size with temp increase from 30oF to 90oF

G) Selection of the Utility Sites for Field Tests

The utility test sites were selected as randomly as possible to obtain measurements representative of the population distribution of leak records and to reduce bias in the emissions estimates. Similar to the earlier GRI-1996 study, the assumption that the participating utilities in the testing program are representative of the target population (i.e., national distribution

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industry) was an important consideration in developing the experimental design and in defining the appropriate sampling. A total of 5 utilities participated in the field tests. Figure 23 shows the locations of the utilities with the field test sites.

Figure 23 ‐ Field tests at utility sites

Figure 24 compares the participating utilities to the top-100 gas distribution utilities which account for about 85 percent of the total distribution services (i.e., about 55.3 million services out of the total 64.9 million) (9).

The data in the figure shows that the participating utilities represent about 14 percent of the service lines of the top-100 utilities. The figure also shows that the percentages of the PE pipes in both mains and service lines in the participating utilities are representative of the national industry, with the PE pipes contributing to about 50 percent of the main lines mileage and 65 percent of the number of service lines.

To prevent bias of the site selection, the test sites were randomly selected from grades 2 and 3 in the utilities leak records without consideration if the pipes are planned for replacement or repair. The classification of these grades varies according to the utilities but mostly follows the GPTC guide for leak classification (10). The guide criteria are summarized in Table 11.

The field measurements did not include tests of grade 1 leaks since this grade represented leaks with probable hazard and required immediate repair. Some of grade 1 leaks have similar leak rates to grade 2, but they are located in areas which are considered hazardous. For the portion of this grade that has larger leak rates; its contribution to the annual emission rate is minimal due to its immediate repair requirement.

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Figure 24 ‐ Comparison of mains and service data in sites and top‐100 utilities

Table 11 ‐ Summary of Leak Classification and Selected Examples (10)

Grade Definition Examples

1 A leak that presents an existing or

probable hazard and required

immediate repair.

‐ Leak with immediate hazard in a location

that may endanger public or property,

‐ Leaks that have ignited gas,

‐ Migrated gas to buildings,

‐ Confined space readings of 80% LEL or

higher.

2 A non‐hazardous leak, but justifies

scheduled repair based on probable

future hazard.

Leaks that require action within 6 months

include:

‐ Readings with 100% LEL or greater under

a street in wall‐to‐wall paved area.

3 A non‐hazardous leak that can be

reasonably expected to remain non‐

hazardous.

‐ Readings under a street in areas without

wall‐to‐wall paving.

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Chapter 5 - Field Measurements at Utility Sites

A) Introduction

The field measurements of gas emissions were performed at LDC companies during the period from June 2011 to December 2012. The measurements were performed at several locations at the 5 utilities shown in Figure 23. Table 12 shows the testing parameters of these sites.

The field measurements were performed on 30 tests. Most of the measurements (21 tests) were performed using the two procedures of surface measurements and flow rate measurements of the isolated pipes. Most of the leaks were at the joints and the leaks in 5 of the tests were located at PE service lines.

The measurements of the service line leaks were performed in sites where they were not initially identified as leaks from the main or the service line. Once identified, they were reported as such in the table. These results were used in the comparison analysis between the surface and belowground measurements.

Table 12 ‐ List of the Emissions Field Test

Test

Site

Test

No.

Line Description Surface

Reading

Belowground

Measurements

Notes

A 1 2‐inch Aldyl‐A main Yes Yes Aldyl‐A 2‐inch main, joint leak

2 2‐inch Aldyl‐A main Yes Yes Aldyl‐A 2‐inch main, joint leak

3 2‐inch PE main Yes No

B 1 1‐inch PE line Yes Yes Joint leak at main

2 ½‐inch PE service line Yes Yes Leak at joint near riser

3 ½ ‐inch PE service line Yes Yes Leak at line below grass area

C 1A 2‐inch PE main Yes No

1B 2‐inch PE main Yes No

1D 2‐inch PE main Yes No

2 4‐inch PE main Yes Yes

3 2‐inch PE main Yes Yes

D 1 2‐inch PE main Yes Yes

2 ½‐inch PE service line Yes Yes



E 1‐5 2‐inch PE mains Yes No 5 sites with gas concentrations between

7%LEL and 25%LEL.

F 1‐10 2‐inch PE pipes Yes Yes Field Testing facility, sites with gas

concentrations between 1% and 30% gas.

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The tests in Site E were performed using the surface measurements procedure only. The testes in Set F were at the field testing facility. These tests were performed in the fall of 2012 at leaks with higher gas concentrations than the ones in the utility tests.

The plastic pipe mains included PE and Aldyl-A pipes and their operating pressures ranged from 50 psig to 60 psig. The following sections present the field tests at the utility sites and testing facility. The results of these tests are presented in Chapter 6.

B) Emission tests at Utility Site [A]

Emission tests were performed on leaks at three locations in site A. Figure 25 to Figure 27 show schematics and details of the three tests. The leaks at these sites were initially measured using the Combustible Gas Monitor (CGM) and had very small gas concentrations, ranging from 4 to 10 percent LEL at the surface. The leaks at tests 1 and 2 were at the joints between the main lines and the service lines. Test 3 had only measurements with the Hi-Flow device.

Figure 25 ‐ Test 1 at the Utility Site A

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Figure 26 ‐ Test 2 at Utility Site A

Figure 27 ‐ Test 3 at utility site A

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C) Emission tests at Utility Site [B]

Emission tests were performed at three leak locations in site B. Figure 28 to Figure 30 show the site details of the three tests. The leak in test 1 was in a stone base surface and was identified at the end cap of the line (see Figure 28-c). The leak in test 2 was near the joint with the riser and leak in test 3 was in the grass areas near the PE joint with the service line.

The methane leak measurements ranged from 20 percent to 70 percent LEL (i.e., 1-3.5 percent gas). The emission measurements in these tests were performed using both the High-Flow device at the surface and belowground leak rates from the excavated bellholes at the main lines.

Figure 28 ‐ Test 1 at the Utility Site B

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D) Emission tests at Utility Site [C]

These tests were performed at 6 leak locations. One of the tests was performed on a steel pipe main leak and was not included in the analysis. The PE mains had diameters of 2 and 4 inches and were in the grass areas adjacent to the roadway. Schematics of the leak locations are shown in Figure 31 to Figure 34.

The methane leak measurements using the CGM gas monitor had small to medium gas concentrations at the surface, ranging from 20 to 75 percent LEL. The emission measurements in tests 2 and 3 were performed using both the High-Flow device at the surface and belowground leak rates from the excavated bellholes.

Most of the leaks in the tests were identified at the joints with the service lines. Figure 34-(b) shows the leak at the joint connection excavated after the completion of the tests.

Figure 31 ‐ Test 1A at the Utility Site C

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Figure 32 ‐ Test 1B at the Utility Site C

Figure 33 ‐ Test 2 at the Utility Site C

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Figure 34 ‐ Test 3 at the Utility Site C

E) Emission tests at Sites [D]

Emission tests were performed at four leak locations in site D. The leaks in Test 1 was in a 2-inch main line and the leaks in tests 2 to 4 were in the PE service lines in the grass areas adjacent to the roadway. The measurements in the service lines were not used in the estimation of the emission factor for the PE mains.

The leak in test 4 was in the joint between the service line and the gas meter riser. Figure 35 to Figure 38 show schematics and details of these tests.

F) Emission tests at Sites [E]

These tests were performed at 5 leak locations in PE mains. Only surface measurements were performed in this site using the Hi-Flow device.

G) Set F Emission tests

These tests were performed at the field testing facility at GTI. The tests were performed on 2-inch PE mains in various soil types. The leak rates in these tests were higher than the ones in the utility sites and ranges from 1 to 30 percent gas. Figure 39 shows the surface measurements at the site.

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Figure 35 ‐ Test 1 at the Utility Site D


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Figure 39 ‐ Flow Rate Measurements at the GTI field testing facility

H) Summary

The leaks at the utility sites were randomly identified from the leak records of the participating utilities. These leaks were grades 2 and 3 and were characterized as small leaks with low rates. The gas concentration measurements at the surface ranged from 10 percent to 100 percent LEL. Grade 1 leaks were not included in the field tests.

Most of the leaks in the mains were characterized as joint leaks, located at the joints between the main lines and the service lines.

The leaks in 5 field tests were identified as service line leaks. The results of these tests were used in the correlation between the surface and belowground measurements and they were not used in estimating the Emission Factor of PE mains.

Further emission rate tests were performed at the field testing facility. These tests had gas concentration readings between 1 to 30 percents gas. The results of these tests were used in the correlation between the surface and belowground measurements. A set of these tests were used with the utility field measurements to provide a representative distribution of the full range of the gas concentrations in the utility records. The following chapter provides more details of the results of the testing program.

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Chapter 6 - Results of the Field Testing Program

The results of the field tests are summarized in Table 13. The results show the maximum gas concentrations and the leak rate measurements using the two testing procedures. The table shows the average leak rates of the Hi-Flow device. The variability of the surface readings of the Hi-Flow device at various leak rates is shown in Figure 40.

The field measurments at the utility sites included leaks which where identified to be in the service lines as shown in the table. These measurements were not included in the estimation of the emission factor of PE mains. Additinally, the table shows a set of tests at the field testing facility which was used to correlate the surface mesurments at high flow rates. These tests were also not included in the estimation of the emission factor.

The statistical description of the surface measurements data for the estimation of the emission factor is shown in Table 14. The results show mean value of 0.055 for the field results with a standard error of 0.014. The estimation of the Emisson Factor for the PE mains from this data is presentd in Chapter 7.

Table 13 ‐ Flow Rate Measurements at the Test Sites

Test Test Max. %Gas Readings Pressure Hi-Flow Device LFE Notes

Site No. [At Surface] (psi) Avg. readings (cfm) (CFM)

1 A 1 70% LEL (Dropped to 10% LEL) 47 0.01 0.003 Aldyl‐A 2‐inch main, joint leak

2 2 48%LEL (dropped to 4%LEL) 48 0.01 0.003 Aldyl‐A 2‐inch main, joint leak

3 3 30%LEL ‐ dropped to 5%LEL 0.01 Readings dropped to zero with time ‐ No digs

4 B 1 70%LEL 40 0.06 0.058 PE end cap joint with main

5 2 20% LEL 39 0.01 0.003 Service line leak ‐ Not used in EF of mains

6 3 2%LEL 52 0.01 0.002 Service line leak ‐ Not used in EF of mains

7 C 1A 45% LEL 40 0.01 Surface readings only

8 1B 25%LEL 40 0.01 Surface readings only

9 1D 75% LEL 30 0.06 Surface readings only

10 2 64% LEL 38 0.24 0.28 4‐inch PE main

11 3 20% LEL 49 0.03 0.045

12 D 1 8% Gas ‐ dropped to 80%LEL 70 0.01 0.017 2‐inch main




16 E 1 30% LEL 0.01 Readings dropped to zero with time ‐ No digs

17 2 7% LEL 0.01 Readings dropped to zero with time ‐ No digs

18 3 12% LEL 0.01 Surface readings ‐ No digs

19 4 [unrecorded] 0.01 Surface readings ‐ No digs

20 5 15% LEL 0.01 Surface readings ‐ No digs

21 F 1 <1 0.25 0.06 0.08 Surface and flow meter tests

22 2 <1 0.25 0.01 0.0082

23 3 1% Gas 2 0.15 0.1695

24 4 1% Gas 31 0.07 0.12

25 5 2% Gas 27 1.07 1.92 Correlations Tests ‐ Not used in EF of mains



28 8 25%Gas 40 0.17 0.18

29 9 30%Gas 30 0.16 0.167

30 10 10%Gas 50 0.1 0.113

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Figure 40 ‐ Variability of the measurements with the pipe leak rates

Table 14 ‐ Descriptive Statistics of the Leak Rates for Emission Factor

The correlation between the Hi-Flow device measurements and the leak rates from the LFE device is shown in Figure 41. The results show a good correlation between the two procedures with a correlation r2 of 0.98. The Hi-Flow readings were typically lower than the LFE measurements and averaged about 0.87 of the LFE leak rate measurements. The LFE meausemtns were multiplied by 0.95 to account for the methane content in the gas composition.

N (No. of Samples) 22

Minimum Value 0.01

Maximum Value 0.24

Mean (scf/leak-hour) 0.0555

Median 0.01

Variance 0.0045

Standard Deviation 0.0672

Standard Error 0.0143

Skewness 1.5079

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It should be noted that the LFE measurements from the belowground leaks were not reduced for the soil oxidation. An oxidation factor of 2 percent was suggested in the GRI-1996 study for the PE mains. This oxidation factor was not included since it was based on the high emission factor estimate of the PE mains in the GRI study. Soil oxidation is highly dependent on the leak rate, as well as other parameters, and the GRI study had a wide range from 2 percent in PE mains to 21.2 percent in the PE service lines.

Figure 41 ‐ Correlation between the Hi‐Flow measurements and pipe leak rates

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Chapter 7 - Emission Factors from Belowground PE Leaks

A) Emission Factor of PE Mains

The LDC companies use leak detection procedures to locate and classify leaks for repair. To identify leaks, portable gas detectors are typically used to screen for leaks immediately above the path of the pipeline. The percentage of measured gas for each leak is commonly recorded in the utility leak database. The leaks are classified in several grades according to the utilities procedures and GPTC general guidelines previously shown in Table 11.

Although the statistical distribution of the leak data in the utility records varies according to the utility leak detection and repair practices, a large percentage of the PE main leaks are characterized as small leaks with low gas concentrations below 5 percent gas. Field measurements of gas emissions at the utility sites also showed that most of the leaks were small leaks, mostly at the joints with the service lines.

Figure 42 shows a typical distribution of gas concentrations from leaks in a utility record. The figure shows that the PE leak records are not normally distributed but have a log-normal distribution; with about 80 percent of the leaks below 10 percent gas readings at the surface.

Figure 42 ‐ Distribution of gas concentration in a typical utility record

In general, emission rates may not be proportional to the gas percentage readings at the surface; large leak areas at the surface may produce high emission rates albeit low gas

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concentration readings at the individual locations. However, gas concentration readings are available in most utility records and they provide a simple check that ranges of all gas leaks in the records were represented in the testing program.

As shown in the previous chapter, most of the leak measurements at the utility sites had low gas leak rates with surface gas readings associated with leak grades 2 and 3. However, the combined measurements at the utility sites and the field test sections provided a representative log-normal distribution of the leaks similar to the utility sites as shown in Figure 43. The descriptive statistics of the gas measurements at the utility records and field tests are shown in Table 15.

The log-normal distribution of the percentage leaks in the PE mains in the above figure shows that the selection of the ‘Mean’ value of the leak rates does not account for the skewness of the data towards the low leak rates, and accordingly does not provide a representative Emission Factor from the leak rates data.

Figure 43 ‐ Distribution of gas concentration readings in the field tests

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Table 15 ‐ Statistics of the Gas Concentrations in Utility Records and Field Tests

In order to incorporate the skewness in the distribution of the leak rates, a weighted function is introduced to incorporate a representative log-normal distribution. The weighted function assumed 80 percent of the leaks below 10 percent gas readings as shown in Figure 42. The weighted function calculations are shown in Table 16 and they result in an updated Emission Factor of 3.72 scf/leak-hour for the PE mains.

Table 16 ‐ Methane Emission Factor Distribution PE Mains

Leak rate Weight

(Log‐normal distribution)

Leaks in sites with <10% gas

surface readings0.042 0.80

Leaks in sites with >10% gas

surface readings0.153 0.20

Estimated Emission Factor0.062 scf/leak‐min

3.72 scf/leak‐hour

B) Comparison with the GRI-1992 Emission Factor

The relatively higher leak rate for plastic mains in the GRI-1996 study (12.45 scf/leak-hour) was the average value (Mean) from a smaller sample of six data points, with one large data point that skewed the average emission rate. Table 17 shows the GRI test data for the PE mains. The small sample size was mainly due to relatively infrequent leaks in plastic mains and the difficulties of identifying suitable plastic main test sites. The GRI report however stated that although the data suggested relatively high leak rates for plastic mains, these pipes experience significantly fewer leaks than the other pipe materials (1).

Utility Records Field Tests

N (No. of samples) 435 22

Min. value (%gas) 1 0.1

Max. Value (%gas) 80 30

Mean (%gas) 10.35172 4.31

Lower Quartile (%gas) 3 0.75

Upper Quartile (%gas) 14 3.5

Stand. Deviation 12.0275 7.856

Standard error 0.5767 1.674

Median (%gas) 6 1.125Skewness 2.3398 2.74

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Table 17 ‐ Descriptive Statistics of the GRI‐1996 Data

The difference between the GRI-1996 estimate of the EF and the current analysis is captured graphically in Figure 44. In the GRI model, the only information used was the results of the six field tests and Figure 44-a represents this casual relationship. In this relationship, the data average (i.e., the Mean) was taken to represent the emission factor of the PE dataset. This approach may result in a misrepresentation of the data, especially if it is not normally distributed around the Mean as demonstrated by the large difference between the Mean and Median values in Table 17.

In the current analysis, the distribution of the leaks in the PE pipe tells us that a log-normal distribution provides a better representation of the leak records, and the estimate of the emission factor should incorporate the skewness in the data towards the low leak volumes.

The current analysis adds additional information represented by the percentage gas concentrations at the sites as shown in the relationship in Figure 44-b. The additional information is added to provide the relevant weights to represent a log-normal distribution for a more accurate estimation of the emission factor.

Figure 44 ‐ Modeling the input‐output relationships in the emission estimates

N (No. of samples) 6

Min. value 0.008

Max. Value 61

Sum (scf/leak‐hour) 74.724

Mean 12.454

Standard error 9.8322

Stand. Deviation 24.0839

Median 1.375

Skewness 2.322

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Chapter 8 - Activity Data and Total Emissions

A) Current Estimates of the Activity Data

Similar to the GRI-1996 study, the new emission factor is calculated in scf/leak-hour units and accordingly, the matching Activity Data is the number of annual equivalent leaks in the LDC records for PE mains. The annual equivalent leak is defined as the number of leaks that leak continuously year round.

An estimate of the annual equivalent leaks from utility data is developed based on the end-of-the year data as following formula:

TEL = OL + LI + UDL + URL - RL [4]

Where,

TEL = Annual equivalent leaks;

OL = Outstanding leaks at the beginning of the year;

LI = Leak indications recorded during the year, including call-ins;

UDL = Undetected leaks which cannot be found using an industry standard survey procedure; estimated as: UDL = [(1/0.85) – 1] X LI,

URL = Unreported leaks that have developed in parts of the network not survey during the current year; and

RL = Sum of [Repaired leak x (Repair date - Report Date)/365].

The RL parameter incorporates the actual duration of leak from the leak repair record. Leak indications and undetected leaks are estimated to be leaking the entire year (i.e., 8760 hours per year).

Table 18 shows the Activity Data for the distribution pipelines from the GRI-1996 study. The estimation of the number of leaks was based on the leak repair records of the utilities. For the plastic pipes, the estimated number of leak repairs in 1992 was about 23,000. The study suggested a leak-repair ratio of 2.14; resulting in a number of equivalent leaks of 49,226. From equation [1] in Chapter 1, the total emission of 4.91 Bscf/year for plastic pipes was the multiplication of number of equivalent leaks with the Emission Factor.

The EPA estimates of the methane emissions from natural gas systems (11) are based on the GRI-1996 study. Since the activity data reported in the EPA inventory are the numbers of miles for all the pipe types, the emission factors were converted to units of scf/mile-year.

The EPA has updated activity data for some of the components in the system based on publicly available data. Table 19 displays the 2008 activity levels.

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Table 18 ‐ Activity Data for Distribution Pipelines (5)

Table 19 ‐ Methane Emissions for Gas Distribution (in Mg), 2008 (3)

Mains Activity Data

(miles) Emission Factor (Mscf/mile‐yr)

Emissions (Mg)

Cast Iron Unprotected Steel Protected Steel Plastic

36,462 69,374 479,502 603,377

239 110 3 10

167,628 147,229 28,324 115,164

Services Activity Data (services)

Emission Factor (Mscf/service)

Emissions (Mg)

Unprotected Steel Protected Steel Plastic Copper

5,388,623 15,456,866 41,573,069 1,140,738

2 0.2 0.01 0.3

176,514 52,543 7,445 5,588

‐ (From Table A‐121, 2008 EPA Adjusted Values) ‐ Mscf = Thousand standard cubic feet

B) Incorporating the Emission Factor with the Activity Data

As shown in Table 19 above, the Emission Factor for the PE mains is 10 Mscf/mile-year. The Emission Factor estimate of 99.845 Mscf/leak-year from the GRI-1996 study (see Table 3) shows a conversion factor of about 0.1 leaks per mile for the PE mains. However, this conversion factor varies with the utilities practices in detecting and repairing their leaks.

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The estimate of the number of leaks per mile is revisited based on LDC data which suggest lower leak rates per mile for the PE pipes. Due to the difficulty in obtaining data from statistically sufficient number of utilities, the national average of leak repair data was used for this estimate as follows:

- The leak data from the top 100 LDC companies (by the number of service lines) was compiled from the DOT annual report (4). These companies represent 85 percent of the total distribution service.

- From the national annual report, the total leaks which were eliminated or repaired in 2012 was 32,283 (based on leaks caused by natural force, excavation damage, other outside force and material; and excluding leaks caused by corrosion, and equipment damage).

- By dividing the number of repairs by the total mileage of mains for the top 100 utilities, the leak repair rate is 0.033 per mile. Although PE leak rates are commonly below the leak rates for other pipe types, this rate was used as the repair rate for PE pipes.

- Using a leak-repair ratio of 2.14 as in the GRI-1996 study, the PE leak rate becomes 0.07 leaks per mile.

- This rate per mile converts the Emission Factor of 3.72 scf/leak-hour to 0.26 scf/mile-hour (or 2.28 Mscf/mile-year) for the PE mains.

- Table 20 summarizes the emission factors per leak and mile basis.

Table 20 ‐ Comparison of the Emission Factor Results

Reported Unites scf/leak-hour scf/mile-hour Mscf/mile-year

This Study 3.72 0.26 2.28

GRI-EPA , 1996 (1) 12.45 - -

EPA, Subpart W, 2010 (2) - 1.13 -

EPA, Emissions Inventory, 2008 (3) - - 10

C) Total Emissions Estimates

As stated in Equation [1], the emission estimates from the natural gas infrastructure are represented by the following equation:

Total Emissions = (Emission factor x Activity Factor)

The use of the number of miles in the Emission Factor and Activity Data is used in the emission estimates in the national emissions inventory.

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In addition to a national estimate based on the pipes mileage for the EPA inventory, local distribution companies may also estimate their total emissions based on the number of leaks in their reporting system. This ‘utility-based’ approach provides a better estimate and reflects the reductions of emissions resulting from the improvements in the utilities leak-repair practices.

In this alternative approach, the utility-based Activity Data are directly determined from their leak and repair records. The use of the number of equivalent leaks (rather than the number of miles) in the Activity Data provides the following advantages:

Uses data already existing in utility repair and scheduled repair records.

Takes into account aggressive leak repair plans which has direct impact on reducing the activity data,

Reflects improvements due to rehabilitation (such as using liners to reduce leaks in cast iron and unprotected steel pipes),

Allows for incorporating recent advances in leak detection methods, thus resulting in a more accurate numbers of leaks.

Easy to update with the improvement in utility leak detection practices.

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References

1. Methane Emissions from the Natural Gas Industry, Volume 9: Underground pipelines. GRI-94/0257.26, EPA-600/R-96-080i, June 1996.

2. 40 CFR Part 98, Subpart W - Mandatory Greenhouse Gas Reporting, Environmental Protection Agency (EPA), 2010.

3. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2008 . U.S. Environmental Protection Agency, EPA No. 430-R-10-006, April 2010.

4. Annual Report Data from Gas Distribution, PHMSA, Office of Pipeline Safety, U.S. Department of Transportation, 2012, http://www/phmsa.dot.gov/pipeline/library/data-stats.

5. Methane Emissions from the Natural Gas Industry, Volume 5: Activity Factors. GRI-94/0257.22, EPA-600/R-96-080e, June 1996.

6. Oxidation of Methane in Soils from Underground Natural Gas Pipeline Leaks. Washington State Univerrsity and University of New Hampshire, Report No. GRI-94/0257.35, Gas Research Institute, July 1996.

7. Improving Methane Emisson Estimates for Natural Gas Distribution Lines, Phase 1, GTI Report 20849, Gas Technology Institute, 2010.

8. Guidance Manual for Operators of Small Natural Gas Systems, Chapter 5: Unaccounted for Gas, Office of Pipeline Safety, PHMSA, 2002.

9. Gas Facts, A Statistical Record of the Gas Industry, American Gas Association , 2012.

10. GPTC Guide for Gas Trasnmission and Distribution Piping Systems, Gas Piping Technology Committee [GPTC] Z380, American Gas Association, 2008.

11. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2011, Annex 3- Methodological Descriptions for Additional Source or Sink Categories, Environmental protection energy (EPA), 2012.

Page 60

List of Acronyms

AD = Activity Data

AGA = American Gas Association

CGM = Combustible Gas Monitor

EPA = Environmental Protection Agency

EF = Emission Factor

FID = Flame Ionization Detector

GPTC = Gas Piping Technology Committee, AGA.

GTI = Gas Technology Institute (formerly GRI, Gas Research Institute).

GWP = Global Warming Potential of a particular greenhouse gas for a given time period.

LDCs = Local Distribution Companies

LEL = Lower Explosive Limit of gas, equals 5 percent methane.

ppm = particle per million

psig = Gauge pressure.

psia = Absolute pressure (psia = psig + atmospheric pressure).

Gas Volume Units:

scf = Standard cubic feet (Standard conditions are at 14.73 psia and 60°F).

scfm = Standard cubic feet per minute.

Mscf = Thousand standard cubic feet (103 scf).

MMscf = Million standard cubic feet (106 scf).

Bscf = Billion standard cubic feet (l09 scf).

Gas Weight Units:

g = gram

Mg (Megagram) = 106 g = 1 metric tonnes

Gg (Gigagram) = 109 g

Tg (Teragram) = 1012 g

MMT = Million metric tonnes = 1 Tg

MMT of CO2 eq. = Million metric tonnes, carbon dioxide equivalent.

Page 61

English to Metric Unites Conversions

Volume Units:

1 ft3 = 0.02832 m3

= 28.32 liters

1 Bscf = 28.32 million cubic meters

1 gallon = 3.785 liters

1 barrel (bbl) = 158.97 liters

1 scf methane = 19.23 g methane

1 Bscf methane = 0.01923 Tg methane

= 19,230. metric tonnes methane

Weight Units:

1 lb = 0.4536 kg

1 short ton (2,000 lb) = 907.2 kg

1 long ton (2400 lb) = 1,016 kg

Pressure units:

1 psig = 51.71 mm Hg

1 psi = 6.896 kPa (kN/m2)

14.5 psi = 1 bar

[END OF REPORT]

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