Applying GIS for gas gathering

As most everybody that works with natural gas pipeline regulations is aware, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published their long-awaited final rule defining onshore gas gathering lines on March 15, 2006, and the rule became effective April 14, 2006. This rule is published in the Federal Register Docket 4868 and includes Title 49 - Part 192 code changes.

Historically, there were some problems; one being the circular reasoning in the definitions of gathering versus transmission for onshore gas pipelines; and another was the use of city limits or municipal boundaries to define which gathering lines were subject to regulation.

With the adoption by reference of the consensus standard published in April 2000 as American Petroleum Institute Recommended Practice 80 (API RP-80) – “Guidelines for the Definition of Onshore Gas Gathering Lines,” the new regulation uses the definitions in API RP 80 to define the points where gas gathering begins and where gas gathering ends, with five limitations imposed by PHMSA. Further, the use of class location and a tier-based risk was used to determine the level of regulation, requiring more stringent regulations for pipelines that pose a greater risk to public safety.

Gathering line regulations

Pipeline operators must use API RP-80 to determine the whether an onshore gas pipeline is a gathering line. API RP 80 defines gas gathering through a series of definitions, descriptions, and diagrams intended to represent the varied and complex nature of production and gathering. Once an operator identifies a pipeline as an onshore gathering line, then they must determine if the line is subject to regulation, and what regulations apply.

Class locations

All Class 1 gas gathering lines are exempt from regulations under Part 192. All Class 3 and 4 gas gathering lines are subject to regulations in Part 192. Class 2 lines may or may not be regulated, depending on additional operating conditions and additional population density analysis.

Part 192.5 defines what a location unit is and what class locations as follows: 

1. A “class location unit” is an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1-mile (1.6 kilometers) length of pipeline. 
2. A Class 1 location is: 
   1. An offshore area; or 
   2. Any class location unit that has 10 or fewer buildings intended for human occupancy. 
3. A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy. 
4. A Class 3 location is: 
   1. Any class location unit that has 46 or more buildings intended for human occupancy; or 
   2. An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.) 
5. A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent.

Type A or Type B

PHMSA used a risk-based classification to establish safety standards for the higher-risk pipelines and to relax current standards on the low-risk gathering lines. The type is determined based on “feature,” which is related to how close the line will be operated to the maximum strength of the line. For metallic lines, it relates the maximum allowed operating pressure (MAOP) to the specified minimum yield strength (SMYS) of the pipeline. This calculation is sometimes referred to as hoop stress or percent SMYS.

Type A lines are metallic lines with a MAOP that produces a hoop stress greater than or equal to 20% of SMYS or non-metallic lines with a MAOP of more than 125 pounds per square inch gauge (psig). By contrast, Type B lines are those metallic lines with an MAOP that produces a hoop stress less than 20% SMYS or non-metallic lines with a MAOP is less than or equal to 125 psig.

What regulations apply?

As mentioned, the level of regulation increases with risk. Two tiers define the levels of risk and establish the safety requirements for these gathering lines. These two tiers are Type A and Type B.

Type A regulated onshore gathering lines must comply with the requirements of DOT Part 192 with the exception of the requirements in §192.150 and in Subpart O. Type A lines in Class 3 and 4 locations must also comply with Operator Qualification requirements. Type A lines in Class 2 locations may demonstrate compliance with Subpart N by describing the processes used by the operator to determine the qualification of persons performing the operations and maintenance tasks.

Type B lines must comply with only 6 requirements. 

1. If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial test must be in accordance with Part 192. 
2. Corrosion Control (metallic pipelines) according to Subpart I. 
3. Damage Prevention Program under 192.614. 
4. MAOP established under 192.619. 
5. Line markers installed and maintained according to 192.707. 
6. Public Education Program established under 192.616.

Figure 1 provides a flowchart of how each of these steps can be applied to metallic lines and Figure 2 provides a similar flowchart for non-metallic lines.

Additional methods for determining whether or not a Class 2, Type B line is subject to regulation are allowed. If the operator determines they have a Class 2, Type B line, the operator can use one of the following three methods to determine whether the line is regulated: 

1. Use traditional Class 2 approach and treat the line as regulated. 
2. Apply an area extending 150 feet on either side of the pipeline centerline for 1 continuous mile to determine if the area includes more than 10 but fewer than 46 dwellings. 
3. Apply an area extending 150 feet on either side of the pipeline centerline for a continuous 1000 feet to determine if the area includes 5 or more dwellings.

For Method b), if there are fewer than 10 dwellings in the designated area, then that portion of the pipeline is not regulated. Likewise for method c), if there are fewer than 5 dwellings in the designated area, then that portion of the pipeline is not regulated. Figure 3 provides a graphic example of all three methods where the line would not be regulated under method b) or c). It should be noted that the operator may choose any method on any line, and is not restricted to selecting one method for all Class 2, Type B lines.

Methods b) and c) require training of personnel to understand the new definitions. Although additional field verification and time are needed to complete the analysis, the regulated footage may be reduced if these other methods are implemented. This is the benefit to operators in applying the non-traditional approach for the Class 2 pipelines.

Compliance deadlines

The following compliance deadlines will be of interest to gas gathering pipeline operators: 

1. An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this section by the date the line goes into service, unless an exception in §192.13 applies. 
2. If a regulated onshore gathering line that exists on April 14, 2006, was not previously subject to this part, an operator has until the date stated in the second column in Table 1 to comply with the applicable requirement for the line listed in the first column. 
3. If, after April 14, 2006, a change in class location or increase in dwelling density causes an onshore gathering line to be a regulated onshore gathering line, the operator has 1 year for Type B lines and 2 years for Type A lines after the line becomes regulated to comply with the applicable DOT requirements.

Conclusion

With the passage of the new Gas Gathering Line Definition; Alternative Definition for Onshore Lines and New Safety Standards Rule, PHMSA has given operators in the gas gathering industry a better definition for gas gathering and allows them to focus resources on the pipelines most critical to ensuring continued protection of public safety. GIS tools are also being integrated with pipeline compliance activities to improve information operators can use in determining if pipelines are regulated. These GIS mapping tools allow operators to perform quick validation of field data, identify encroachment, and take other proactive measure to help protect their assets and maintain pipeline integrity. 

Acknowledgment

Based on a paper presented at the GITA 16th Annual GIS for Oil & Gas Conference, September 26, 2007, in Houston, Texas.