Background

The U.S. Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) was created under the Norman Y. Mineta Research and Special Programs improvement Act (P.L. 108-426) of 2004. Acting through the Office of Pipeline Safety (OPS), PHMSA administers DOT’s national regulatory program to assure the safe transportation of natural gas, petroleum, and other hazardous materials by pipeline. OPS develops regulations and other approaches to risk management to assure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities. Since 1986, the entire pipeline safety program has been funded by a user fee assessed on a per-mile basis for each pipeline operator OPS regulates. The creation of PHMSA provides DOT with an agency focused solely on its pipeline and hazardous materials transportation programs. PHMSA’s mission is to protect the American public and the environment from the risks inherent in transportation of hazardous materials – by pipeline and other modes of transportation. PHMSA has the daily responsibility of overseeing 2.3 million miles of the nation’s pipeline network and strives to meet the needs of the American public by ensuring communities remain safe, livable and free from transportation incidents involving hazardous products.

In 2008, TransCanada Keystone Pipeline, LP (“Keystone”) filed a Presidential Permit application with the U.S. Department of State (DOS) to construct and operate the Keystone XL Pipeline (“Keystone XL”). DOS has taken three years to evaluate Keystone XL’s potential impacts to the environment. DOS consulted extensively with PHMSA throughout this review process. in February of 2011, PHMSA recommended that, above and beyond the requirements of current pipeline code, DOS should impose a set of 57 Project-specific Special Conditions (“Special Conditions”) if a Presidential Permit were to be granted to Keystone to construct and operate the Keystone XL pipeline. Specifically, PHMSA suggested that DOS require Keystone to include all of the Special Conditions in its written design, construction, and operating and maintenance plans and procedures. Keystone willingly accepted these conditions and the State Department’s Final Environmental impact Statement (FEiS) recognizes the significance of Keystone’s adoption of the conditions.

“In consultation with PHMSA, DOS determined that incorporation of the Special Conditions would result in a Project that would have a degree of safety greater than any typically constructed domestic oil pipeline system under current regulations and a degree of safety along the entire length of the pipeline system that would be similar to that required in high consequence areas as defined in the regulations.” -DOS FEIS, Executive Summary (ES-6}

 

Summary PHMSA’s 57 Special Conditions for Keystone XL

Pipe Design and Manufacturing

The first nine Special Conditions present design standards to be used in manufacturing the pipe and requirements for pipe materials, pipe inspections at the mill and in the field, performance tests, and quality control procedures.

System Design, Construction and Testing

Conditions 10 through 23 address design and construction of the proposed Project, including testing of Project components. Those Conditions present requirements for aspects of the proposed Project such as field coatings, depth of cover over the pipeline, temperature and overpressure control, welding procedures, and testing prior to operations. Requirements include hydrostatic testing, a process that pumps water through the pipeline at minimum of 125 per-cent of the maximum allowable operating pressure. The hydrostatic testing has two aspects: a strength test to ensure that the pipe will not break; and a leak test to ensure that there are no defects in the pipe. Operations will not begin until the entire system has passed the required hydrostatic testing.

Integrity, Operations, Maintenance, and Monitoring

Conditions 24 through 49 present the requirements for the Supervisory Control and Data Acquisition (SCADA) system that would be used to remotely monitor and control the pipeline, as well as requirements for internal corrosion inspection, cathodic protection, identification of the location of the pipeline with aboveground markers, internal pipeline inspections using electronic sensing devices termed “smart pigs,” visual monitoring of the pipeline corridor, and repair procedures. Operating 24 hours a day, seven days a week, the SCADA system would alert the Operations Control Center of an abnormal operating condition, indicating a possible release of oil. The system would include automatic features that would ensure operation within prescribed pressure limits. There would also be a complete backup system.

Keystone utilizes four methods of computerized leak detection:

1) Pipeline pressure is the primary indicator used by the SCADA system to detect an oil spill. if the monitoring system identifies a pressure change in the pipeline, the Pipeline Controller has a limited period of time to evaluate the data to determine if it is a false alarm or an actual spill; unless a leak is ruled out within that time period, the system is shut down. Expected performance threshold: 25%-30% of design flow rate, virtually immediately.

2) The SCADA system will also perform an automatic volume balance over the entire pipeline to identify any discrepancies in the volume entering the pipeline and the volume exiting the pipeline. Alarms are generated on a defined volume imbalance. Expected performance threshold: approximately 5% of design flow rate over one hour. Larger leaks are detected much sooner.

3) A computer-based model of the pipeline is used to compare predicted pipeline performance (flows, pressures, temperatures) with actual performance data received via the SCADA system. Detection is on a pipeline segment basis (pump station to pump station). Expected performance threshold: approximately 2% of design flow rate over two hours. Larger leaks are detected much sooner.

4) Trending daily volume balances for each pipeline segment (pump station to pump station) over time will enable trained Operators to identify imbalances indicating a possible small leak event that is below the threshold of the other systems. Expected performance threshold: less than 2% of design flow rate over days.

In addition to computer monitoring, there would be scheduled aerial patrols of the pipeline right-of-way as well as damage prevention and public and landowner awareness programs. Communities along the pipeline would be given information to facilitate the reporting of suspected leaks and events that could suggest a threat to pipeline safety.

Reporting, Record Keeping, and Certification

The final eight conditions present requirements for maintaining detailed records, developing of a right-of-way management plan, reporting to PHMSA, and providing PHMSA with certification from a senior officer of Keystone that it has complied with the Special Conditions.

The complete 57 Project-specific Special Conditions can be found as Appendix U of the Final EIS. Please visit the Project Document section of www.keystonepipeline-xl.state.gov

 

Highlighted Results of the PHMSA Special Conditions

• One of the most rigorous steel and pipe manufacturing surveillance programs for a high-strength steel (X-70 and greater) large-diameter pipe of significant length.

• Among the highest enforceable fracture toughness for any onshore liquid pipeline in the US.

• Significant level of Non-Destructive Examination (NDE) performed throughout the pipe manufacturing program.

• Mill hydrostatic testing up to 100% Specified Minimum Yield Strength (SMYS).

• One of the most rigorous coating survey and repair program requirements in the pipeline industry.

• Jeeping pipe coating (to detect flaws in the coating) at 2500V at the mill. Each pipe mill and coating supplier indicated this is the highest voltage they have ever used to jeep pipe.

• A contributing pipe segment analysis recommended installing heavy wall pipe upstream, downstream and throughout many streams leading to a 100-foot wide water body.

• Enforceable limit on operating temperature (150F). Specific integrity requirements triggered by operation of the pipeline above 120F.

• A requirement to maintain 48″ depth of cover in cultivated areas.

• A firm spacing requirement on remotely Actuated Mainline Valves (AMV).

• A requirement to have the capability to remotely operate valves in the event of a commercial power outage.

 

Individual Summary of PHMSA 57 Special Conditions for Keystone XL

Special Conditions 1-9: Material Requirements

1. Steel must be of high quality with specific materials structure and composition.

2. Pipe must be manufactured with adherence to the most up to date pipe.

3. Requirement for fracture control plan to produce pipe with resistance. Properties to crack initiation and propagation. This is not required by current Federal code for a liquid line.

4. Steel plate/coil quality control. Substantial pipe mill Quality Assurance (QA)/Quality Control (QC) plan, which includes enhanced testing and tolerance requirements.

5. QC requirements for pipe weld seams.

6. Inspection for pipe seam fatigue from pipe transportation from mill to construction site.

7. Puncture resistance properties to mitigate excavator damage.

8. Hydrostatic testing in the pipe mill to 95% of the pipe material’s Specified Minimum Yield Strength (SMYS). SMYS is the maximum strength value of the pipe material without causing permanent material deformation.

9. Application of corrosion resistant coating in accordance with a QC program. And holiday detection of coating disbondment using highest voltage (2500V) specified over current Canadian Standards Association (CSA), National Association of Corrosion Engineers (NACE) and international Standards Organization (iSO) standards.

Special Conditions 10-23: Construction Requirements

10. Implementation of a field joint coating QC program. Holiday detection of coating disbondment using highest voltage (2500V) specified over current CSA, NACE and ISO standards. Only trained applicators can apply coating.

11. Use of abrasion resistant coating for trenchless installations such as bores and Horizontal Directional Drilling (HDD).

12. Implement procedures for high quality welding of components such as fittings with use of material preheat procedures.

13. Traceability of all components (valves, flanges, gaskets, fittings) to the correct intended operating pressure.

14. A design review no later than 6 months prior to construction with PHMSA. Demonstrating design is compliant. Overland spill analysis and yearly survey to identify any changes on the pipeline system that would impact design.

15. Temperature control limit of 120F on station discharge not to exceed 150F. Requirements for coating surveys to be conducted should 120F be exceeded to demonstrate coating integrity in addition to dig ups on the pipeline to correlate survey results.

16. Overpressure control requirements for the pipeline to prevent the pipeline from exceeding 110% of its maximum operating pressure. Surge analysis and installation of pressure and temperature transmitters.

17. Construction plans and schedules must be submitted to PHMSA at least 90 days prior to construction.

18. Notice to PHMSA 21 days prior to commencement of welding procedure development. Submission of welding procedures, stress analysis, lowering in procedures, engineering critical assessments for weld examination to PHMSA.

19. Installation of pipeline at 48-inch cover and maintenance at 48-inch cover in agricultural areas and 42-inch in all other areas except consolidated rock (36-inch cover). Conduct depth of cover survey once every 10 years.

20. Operator Qualification: Require contractor’s personnel to be qualified through third party verification for all tasks that affect the pipeline’s integrity.

21. Assess and implement as necessary Alternating Current (AC) interference controls.

22. Hydro-test the pipeline to 100% SMYS for minimum of 8 continuous hours.

23. Conduct a failure analysis should a test failure occur and prove the failure is not systemic through validation work.

Special Conditions 24-57: Operations and Maintenance

24. Install sophisticated computerized Supervisory Control And Data Acquisition (SCADA) system to provide remote control and monitoring of the entire pipeline system.

25. Enhance SCADA scan rate to detect small leaks within technology limits. implement all findings in National Transportation Safety Board (NTSB) study on SCADA and safety.

26. implement an alarm management policy at any location where the SCADA system is used.

27. implement recommended practices of American Petroleum institute (APi) 1130 recommended practice for Computational Pipeline Monitoring (CPM).

28. Develop a thermal hydraulic model and simulator.

29. Train and qualify all operations control personnel inclusive of simulation training.

30. Develop a calibration and maintenance plan for SCADA.

31. Develop a leak detection manual.

32. install valves at a maximum 20-mile interval. install back up communications and back up power to remotely close valves during inclement weather. This requirement is substantially more stringent than the standard valve placement requirement.

33. Design pipeline to allow for 100% internal inspection by smart tools.

34. Limit sediment and water content to 0.5% by volume. Run cleaning tools twice per year in the first year and as necessary based on integrity analysis. implement crude oil monitoring and sampling program to ensure products transported meet pipeline specification.

35. Installation of Cathodic Protection (CP) system within 6 months of in-service.

36. Conduct stray current interference studies and install mitigation if required.

37. Conduct CP corrosion surveys and install test leads every 1.5 miles as practicable.

38. Conduct CP performance surveys.

39. Conduct coating performance surveys and perform dig ups along the pipeline to verify coating condition.

40. Install line of sight pipeline markers.

41. Conduct right-of-way patrols every three weeks but at least 26 times per year.

42. Conduct baseline geometry internal inspection run post hydrostatic test. Conduct smart inspection (ILI) within the first 3 years of operations.

43. Comply with PHMSA low yield strength advisory stipulations.

44. Conduct future internal inspection at intervals based on fatigue analysis.

45. Complete fatigue analysis annually for the first 5 years.

46. Complete flaw growth assessment.

47. Develop a direct assessment plan for any applicable areas that cannot be inspected internally such as by pass headers.

48. Implement the Common Ground Alliance Damage Prevention Program best practices into pipeline damage prevention program.

49. Complete immediate, within 60 days and within 180 days, dig ups to investigate and/or repair as necessary based on various dimensional criteria for anomalies reported by smart inspection. Remove all dents reported exceeding 2% from the pipeline.

50. Provide immediate notification in the event of reportable incident. Provide notification within 24 hours of all non-reportable incidents.

51. Report on compliance to all conditions within 180 days of in-service.

52. Provide annual report of all integrity management programs and findings.

53. Develop a threat matrix for the pipeline.

54. Develop right-of-way management plan to comply with Conditions 19, 40, 41, 48, 53.

55. Maintain all records for the life of the pipeline.

56. Certification from an Executive Officer of the Company of compliance to Conditions, plans, procedures and programs.

57. Within 1 year provide technical briefing to PHMSA on compliance and items required in Condition 52.

 

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