CHAPTER 8: LEAK DETECTION AND CONTROL
TABLE OF CONTENTS
Page
Introduction................................................................................................................................................1
Properties of Natural Gas..........................................................................................................................1
Carbon Monoxide..................................................................................................................................1
Leak Causes..............................................................................................................................................2
Leak Investigation Definitions....................................................................................................................2
Detection Instruments................................................................................................................................3
Flame Ionization....................................................................................................................................3
Optical Methane Detectors....................................................................................................................3
Combustible Gas Indicators..................................................................................................................4
Interpreting CGI Gas Readings on the LEL Scale................................................................................5
Leak Classification.....................................................................................................................................6
Leak Investigation and Pinpointing............................................................................................................8
Leakage Surveys.......................................................................................................................................9
Types of Gas Leakage Surveys...............................................................................................................10
Mobile Survey.....................................................................................................................................10
Walking Survey...................................................................................................................................11
Vegetation Surveys.............................................................................................................................12
Special Leakage Surveys....................................................................................................................13
Leak Records...........................................................................................................................................13
Leak Investigations..................................................................................................................................14
Leak Sources......................................................................................................................................14
Detection Instruments.........................................................................................................................14
Leak Investigation Process.................................................................................................................15
LIST OF TABLES
Page
Table 8-1: Leak Classification and Action Criteria – Grade 1...................................................................6
Table 8-2: Leak Classification and Action Criteria – Grade 2...................................................................7
Table 8-3: Leak Classification and Action Criteria – Grade 3...................................................................8
Table 8-4: Distribution System Survey Locations...................................................................................10
Table 8-5: Transmission Line Survey Locations.....................................................................................10
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LIST OF FIGURES
Page
Figure 8-1: Flame Ionization Unit..............................................................................................................3
Figure 8-2: Optical Methane Detector on Truck........................................................................................4
Figure 8-3: Combustible Gas Indicator Equipment...................................................................................5
Figure 8-4: Conducting a Mobile Survey................................................................................................11
Figure 8-5: Performing a Walking Survey...............................................................................................12
Figure 8-6: Possible Gas Leak Identified by Vegetation.........................................................................13
CHAPTER 8: LEAK DETECTION AND CONTROL
Introduction
Gas utility companies give top priority to leak investigation given the hazards and potential loss of revenue. This means the investigation of leak and odor complaints must be carried out promptly and thoroughly to ensure safety of gas facilities, employees, and the public.
Natural gas is odorized to produce a characteristic gas smell so that consumers can detect natural gas leaks. Leak indications are received from customers, scheduled surveys, emergency providers, and the general public. Leaks must be classified to quickly determine the extent of the hazard and the required response time for problem resolution. A natural gas leak is defined by the Department of Transportation as, “...an unintentional escape of gas from the pipeline.” A gas operator’s response to a leak will vary widely depending on the severity of the leak and the conditions surrounding it. These conditions may include pipe age, material, condition, operating pressure, leak history, location, and potential for migration.
Proper response requires an understanding of gas properties, leak causes, classifications, and appropriate investigation.
Properties of Natural Gas
Natural gas is lighter than air and will attempt to rise. When released into the atmosphere, natural gas will rise and quickly mix with air. Natural gas will follow the path of least resistance, and it can accumulate far away from an initial leak by traveling through sewers and underground duct lines. A danger may exist even though you are not close to the leak source. Many other petroleum vapors are heavier than air and can collect at the bottom of an opening or confined space.
Natural gas is tasteless, colorless, and odorless. As a result, a separate compound is added to make it easier to detect. Mercaptan, an organic sulfur compound, is added to natural gas by gas companies to give it an identifiable odor. This odor intensity may be decreased or masked if gas passes through areas of decayed matter or various soil compositions.
Natural gas is nontoxic and safe for you and the environment. It contains no poisonous ingredients that can be absorbed into the blood when inhaled. However, if natural gas is leaking, especially in large quantities, it can displace oxygen in the air and result in suffocation.
Natural gas is flammable. For combustion to occur, the proper proportions of natural gas, air, and heat are required. More specifically, combustion will take place only if the percentage of natural gas in the air is between 5% and 15%.
Carbon Monoxide
Carbon monoxide (CO) is a colorless, odorless, highly toxic, non-irritating gas formed by incomplete combustion of any fuel that contains carbon. CO enters the body only through the respiratory system, acting as an asphyxiant, which excludes oxygen from the body. The amount of CO absorbed in the blood of an individual depends on the CO concentration in the air, the duration of exposure, and the individual’s level of physical activity and health.
The limit for carbon monoxide in the flue products of a vented appliance such as a central heating plant, room heater, automatic water heater, or fireplace with a closed front is .03%. The limit for unvented appliances (e.g., an oven or fireplace with a closed front), the limit is .005% CO.
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Leak Causes
Gas leakage may be caused by various conditions such as corrosion, third-party damage, and others listed here.
Corrosion occurs when a small current of electricity flows off of a pipe and into the ground, causing a pipe to deteriorate and possibly leak. Steel pipe and fittings are particularly susceptible to this type of corrosion. Cast iron and ductile iron undergo a corrosive process known as graphitization. Cast iron mains tend to corrode uniformly and have thicker walls. However, if the graphitic area is soap-tested, it may bubble over the entire surface and probably should be replaced.
Cast iron pipe is especially susceptible to cracking. Because of the low strength and ductility of cast iron, 4-inch or smaller pipe is often cracked by secondary stresses—settling, frost heaving, and ground vibration from heavy traffic. Cracking most commonly occurs at points of weakness, such as tap holes and locations where the main has been disturbed.
Damage by outside forces such as lightning, earthquakes, and mud slides can also cause damage to pipelines that result in leaks. Third-party damage means that gas lines are struck by excavation crews using earth-moving equipment and tools. Vandalism of property can also result in gas leaks. Construction defects may result in leaks from damage such as dents, scratches, gouges, or improper installation. Material defects can produce a leak. Gas leaks may result at fittings such as band clamps, split sleeves, threads, or valves. Rubber gaskets can deteriorate or undergo cold flow and leak.
Leaks frequently occur at cast iron bell-joints. Most bell-joint leaks have been attributed to the drying, shrinking, and deterioration of the jute packing. However, studies have shown that jute packing cannot be compacted tightly enough with standard caulking tools to form a seal that is gastight, even against low pressures. The seal in a bell-and-spigot joint was formed by the lead or cement backing, not by the packing. Failure of this seal is the result of joint movement caused by traffic vibration, thermal expansion and contraction, frost heaving, and settling of the pipe. Drying and shrinking of tar and gum deposits from manufactured gas are believed to cause the increases in joint leakage reported after a changeover.
Leak Investigation Definitions
Common terms used in leak investigation are defined below:
Bar Hole: An opening made through soil or pavement for the purpose of testing subsurface atmosphere. When the ground surface over the pipe is not paved, a bar hole can be made by driving an impact bar into the earth to pipe depth, and then removing the rod. The hole is made beside, rather than directly over, the line to avoid damage to the pipe coating. Power-driven equipment is used to drill holes through paving.
Business Districts: Areas with pavement from building wall to building wall, where business activity principally takes place. Federal code defines a business district as a Class 4 Location. This class refers to an area that extends 220 yards on either side of any continuous 1-mile length of pipe where buildings with four or more stories above ground are prevalent. For a complete definition of class locations, refer to Title 49 of CFR 192 subpart A.
Lower Explosive Limit (LEL): The minimum concentration of a combustible gas in air that is explosive or capable of ignition. For natural gas, the lower explosive limit is approximately 5%. The upper explosive limit for natural gas is 15% of gas in air. Levels of gas in air above 15% are too rich to burn.
Liquefied Petroleum Gas (LPG): A gas composed of propane, butane, or mixtures of these gases, or natural gas supplements such as propane air mixtures. Liquefied petroleum gases⎯other than natural gas supplements⎯have a specific gravity greater than 1.0.
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Detection Instruments
Leak detection instruments include Flame Ionization (FI) units, Optical Methane Detectors (OMD), and Combustible Gas Indicators (CGI). All leak detection equipment must be inspected, tested, and calibrated at frequencies specified by your company.
Flame Ionization
Flame Ionization (FI) units are used when conducting both walking and mobile surveys to detect potential gas leaks and help determine gas migration. FI units draw an atmospheric sample across a hydrogen gas flame, which creates a current of ionized particles. The amount of current is converted to a parts per million (ppm) scale and alarms at a preset point.
Figure 8-1: Flame Ionization Unit
FI units do not provide readings below grade or an accurate measurement of gas concentration. Although they are very sensitive, FI units are susceptible to false readings from decayed vegetation, animal waste, and other hydrocarbons. They should not be used to survey in cold weather and must not be used indoors or in confined spaces because they are not intrinsically safe.
Operating guidelines for the FI unit are as follows:
• Introduce the correct test gas to calibrate instrument. Adjust the zero point and alarm values in a hydrocarbon free atmosphere.
• Confirm that fuel cylinders are filled to allow operation for the expected survey time. Do not allow the fuel cylinder pressure to drop below the specified minimum value. If the cylinder pressure drops too low, contamination may result.
• Install a new primary filter before each use. Replace the filter daily or more often, as required. Clean the sample probe and replace any probe filters before each use.
• Purge, ignite, and warm up the FI unit according to manufacturer's instructions. Check battery capacity after warmup of unit.
• Perform a field check of FI instruments as specified in your company procedures.
Optical Methane Detectors
Optical Methane Detectors (OMDs) are used to conduct mobile surveys and are capable of detecting methane down to 1 part per million. OMDs utilize an infrared light source directed at an infrared optical detector. When the OMD passes through a plume of natural gas, methane in the plume absorbs some of
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the infrared light reaching the detector. This decrease in infrared light is converted to ppm and sounds an alarm if the set point is reached.
Figure 8-2: Optical Methane Detector on Truck
Optical Methane Detectors can operate during dry and wet weather under temperatures from -20ºF to +110ºF. OMD units (like an FI) are not designed to accurately measure gas concentration and are susceptible to false readings from decayed vegetation, animal waste, and other hydrocarbons.
Operating guidelines for OMD are as follows:
• Optical path must be clean and properly aligned.
• Unit must be warmed up for one hour before performing operation and calibration checks. If the reading varies more than ± 5 ppm from the set point, check the internal test cell.
• Proper operation must be verified during the survey by periodically depressing the test button.
• Calibration check must be performed at the beginning of each day, immediately after the operational test. (A test cell containing a fixed concentration of methane is placed within the path of the sensor.) If the reading varies by more than ± 10% within a range of 1 to 100 ppm, the instrument must be recalibrated by a trained technician.
Combustible Gas Indicators
A Combustible Gas Indicator (CGI) is an electronic instrument used to detect and measure concentration of combustibles and pinpoint leaks. CGIs are manufactured as single-scale or two- scale instruments. Single-scale CGIs have the lower scale only. Two-scale instruments have both a lower and upper scale. The lower scale has a range of from 0 to 100% lower explosive limit (LEL). A reading of 100% LEL corresponds to a reading of at least 5% natural gas in the air. The upper scale reads from 0 to 100% natural gas.
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Figure 8-3: Combustible Gas Indicator Equipment
A Combustible Gas Indicator must be used to verify and classify all leaks. Employees assigned to FI or OMD surveys must be qualified in the operation of a CGI. A CGI is susceptible to false readings from decayed vegetation, animal waste, and other hydrocarbons.
Listed here are the operating guidelines for CGIs:
• A CGI contains flame arresters on the inlet and outline side of the instrument. Flame arresters should never be removed or tampered with.
• Operational tests should be conducted prior to each use to verify that the sampling system is free of leaks, filters are not obstructing sample flow, battery strength is sufficient, and it is at zero adjustment.
• A CGI should be calibrated against a standardized test according to the method and frequency specified in company procedures. It must also be calibrated after incidents and if operating problems arise. Test information should be recorded according to company procedures.
• A CGI must always be purged with clean air before starting and when finishing a sample. Leaving a sample inside the instrument can burn out a filament. This may lead an operator to conclude there was no gas because readings would not occur. If a CGI is turned on and aspirated in a combustible atmosphere, the instrument can be improperly zeroed and the instrument will read below the actual concentration.
• In general, cold temperatures and old batteries will cause readings on the LEL scale to be less than the actual concentration. On two-scale instruments, the % gas scale will read higher than the actual concentration.
• A CGI will respond to petroleum vapors such as gasoline and other hydrocarbons, but the readings will be incorrect because the instrument was calibrated on natural gas. A charcoal filter will absorb petroleum vapors. If readings decline to zero after a filter is installed, petroleum vapors are indicated. If readings continue with and without a filter, natural gas is present.
If a CGI is exposed to leaded gasoline without a charcoal filter installed, the lead will gradually coat the sensor and the readings will be too low. Problems can also result from other contaminants. A CGI will also respond to marsh or sewer gas that contains high levels of methane (but no ethane). Lab analysis is required to determine if a sample contains ethane.
Interpreting CGI Gas Readings on the LEL Scale
When sampling is conducted using the instrument's lower LEL scale, it is critical that the meter be continuously monitored from the beginning to the end of the test to interpret the readings correctly. If the meter remains at 0 after a sample is taken, you can conclude that there is no gas present. If the meter moves to the right and remains on scale, a gas-to-air concentration below the LEL limit of 100% is
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detected. If the meter moves to the top of the scale and immediately falls back down to or below 0, this indicates that the gas-to-air mixture is above 100% LEL.
Leak Classification
All leaks must be classified, acted upon, and reported according to company procedures. All tests, calibrations, and survey information must also be recorded. Safety-related conditions, follow-up maintenance items, and other required documentation should be reported as necessary.
Guidelines for leak classification and control are provided in Tables 8-1, 8-2, and 8-3. The examples found in the tables are guidelines and are not exclusive. The judgment of the company personnel at the scene is the primary determinant of the grade assigned to a leak. When a leak is to be re-evaluated (see Tables 8-2 and 8-3), it should be classified using the same criteria used when the leak was first discovered.
Table 8-1: Leak Classification and Action Criteria – Grade 1
Grade
Definition
Action Criteria
Examples
1
A leak that represents an existing or probable hazard to persons or property, and requires immediate repair or continuous action until the conditions are no longer hazardous.
Requires prompt action* to protect life and property, and continuous action until the conditions are no longer hazardous.
Any leak, which in the judgment of operating personnel at the scene, is regarded as an immediate hazard.
Escaping gas that has ignited.
Any indication that gas has migrated into or under a building or into a tunnel.
Any reading at the outside wall of a building, or where gas would likely migrate to an outside wall of a building.
A reading of 80% LEL, or greater, in a confined space.
A reading of 80% LEL, or greater in small substructures (other than gas associated substructures) from which gas would likely migrate to the outside wall of a building.
A leak that can be seen, heard, or felt, and in a location that may endanger the general public or property.
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*The prompt action in some instances may require one or more of the following.
Implementing company emergency plan (192.615).
Evacuating premises.
Blocking off an area.
Rerouting traffic.
Eliminating sources of ignition
Venting the area.
Stopping the flow of gas by closing valves or other means.
Notifying police and fire departments
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Table 8-2: Leak Classification and Action Criteria – Grade 2
Grade
Definition
Action Criteria
Examples
2
A leak that is recognized as being non-hazardous at the time of detection, but justifies scheduled repair based on probable future hazard.
Leaks should be repaired or cleared within one calendar year, but no later than 15 months from the date the leak was reported. In determining the repair priority, criteria such as the following should be considered:
Amount and migration of gas.
Proximity of gas to buildings and subsurface structures.
Extent of pavement
Soil type, and soil conditions (such as frost cap, moisture and natural venting).
Grade 2 leaks may vary greatly in degree of potential hazard. Some Grade 2 leaks, when evaluated by the above criteria, may justify scheduled repair within the next 5 working days. Others will justify repair within 30 days. During the working day on which the leak is discovered, these situations should be brought to the attention of the individual responsible for scheduling leak repair.
Many Grade 2 leaks, because of a less critical location and magnitude, can be scheduled for repair on a normal routine basis with periodic re-inspection as necessary.
Leaks requiring action ahead of ground freezing or other adverse changes in venting conditions.
Any leak which, under frozen or other adverse soil conditions, would likely migrate to the outside wall of a building.
Leaks requiring action within six months.
A reading of 40% LEL, or greater, under a sidewalk in a wall-to-wall paved area that does not qualify as a Grade 1 leak.
A reading of 100% LEL, or greater, under a street in a wall-to-wall paved area that has significant gas migration and does not qualify as a Grade 1 leak.
A reading less than 80% LEL in small substructures (other than gas associated substructures) from which gas would likely migrate, creating a probable future hazard.
A reading between 20% LEL and 80% LEL in a confined space.
A reading on a pipeline operating at 30% SMYS, or greater, in a class 3 or 4 location, which does not qualify as a Grade 1 leak.
A reading of 80% LEL, or greater, in gas associated substructures.
A leak which, in the judgment of operating personnel at the scene, is of sufficient magnitude to justify scheduled repair.
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