What’s in Print

Tracer Gas Assessment Program paying off at Phillips 66

THERE has been an increased focus in the industry on improving facilities through integrity programs.

The statistics tell why: According to the American Petroleum Institute’s Pipeline Performance Tracking System (PPTS) data, in 2015, facilities led all locations in number of releases (225)—nearly twice as many as onshore pipelines (125) and well ahead of storage tanks (50). Equipment failure was the most common cause, followed by corrosion, excavation/outside force, incorrect operation, and natural force.

In his presentation, “Leak Detection in Terminal Facility Piping,” Sam Adams, a maintenance engineer in Phillips 66’s midstream division, said Phillips 66 developed an integrated Tracer Gas Assessment Program that has the ability to test all underground piping without interfering with operations. Adams discussed the testing system during the 37th Annual International Liquid Terminals Association’s International Operating Conference.

It’s a tracer-based method using small amounts of inert compounds (“tracers”) to detect small leaks.

“It was a great method for us to get the current status of a leak or no-leak type of situation in our facilities without disrupting operations,” he said.

He said other advantages of tracer gas are that it is a global, online, non-destructive method and is cost effective.

He explained the tracer gas assessment and detection process by outlining the pre-work in the year prior to execution:

•  Select facility based on established criteria.

•  Review schedule with TGT contractor and maintenance integrity coordinator and develop budget estimate.

•  Conduct onside logistic coordination and review with facilities.

•  Establish preliminary target dates and notify facilities.

•  Develop a detailed proposal and work plan.

•  Document decisions and actions on pre-plan.

And then the execution:

•  Confirm schedule with facilities.

•  Initiate management of change.

•  Establish target probe install and inoculation dates.

•  Install probes per pre-plan.

•  Inoculate per pre-plan.

•  Collect and analyze samples.

•  Contractor to notify maintenance coordinator of test status.

•  If not OK, delineate anomaly. If anomaly is confirmed, document and resume TGT. If leak is confirmed, facility will initiate repair process.

•  After repair is completed, resume TGT.

•  If OK, maintenance to notify site and facility integrity group.

•  TGT contractor to forward final document to facility and facility integrity group within 30 days.

•  Schedule next test based on results.

He said 51 facilities were tested throughout the Phillips 66 system.

“Initially, in developing the program, we were thinking we’d do a retest every five years,” Adams said. “But after our first few years of working with facilities, we realized it might not be the most logical or efficient use of our resources. Based on our findings and overall risk, we developed a more logical and productive retest interval.”

Two years ago, Phillips implemented this tracer gas retest frequency program:

In a low-consequence area with no leak history, the maximum tracer gas testing frequency is 10 years for refined product and ethanol (PWHT), and seven years for crude, ethanol (no PWHT), and drains/process water. For medium/high-consequence areas with no leak history, the maximum tracer gas testing frequency is seven years for refined product and ethanol (PWHT), and five years for crude, ethanol (no PWHT), and drains/process water.

For those areas with a leak history, the maximum tracer gas testing frequency is five years for refined product and ethanol (PWHT), and three years for crude, ethanol (no PWHT), and drains/process water.

Positives were detected at six of the facilities tested: three drain systems; one dead leg; one ethanol flange pair; and one water draw.

“One thing to keep in mind when forming assessments is, you’re not going to find a large-scale release,” he said. “We’re looking for those very small, very limited-volume releases.

“We want to make sure we have a validated process versus just pulling the fire alarm and running to excavation. The majority of our instances have been a combination of lack of penetration from wells and collection of water.”

Lessons learned:

•  Structure validation process for positives. “This is just to confirm you truly have a positive. You don’t want to have to shut down operations for a false positive.

•  Tracer gas is very accurate for detection.

•  The main cause of failure on buried piping is internal corrosion.

•  Opportunities: tracer gas detection on dead legs and failure cause analysis and trending.

Ian Harris, who works in business development at Praxair Services Inc, shared the presentation with Adams and gave the technical side of tracer gas assessment.

He said it can be performed while the facility remains in-service; can detect and locate leaks of any size; is applicable on any piping design; and is not affected by pre-existing hydrocarbons in the soil.

“You inject a small amount of inert tracer compound into fuel,” he said. “You then install small vapor sampling probes adjacent to piping. These probes are literally ¾-inch PVC that allow a mechanism to collect at a later date. You collect soil vapor samples and analyze for the presence of tracer in the soil. Then if you detect something, you can pinpoint that as needed.

“It’s a very simple process. You would inject directly into the piping by tapping into any fitting along the line as fuel is moving by or through associated storage tanks. Typically, the probes are two feet in depth. They’re manually installed vertically. It’s almost like a rod device that pushes the PVC down. You pull the rod back and the PVC stays in the ground. They become a mechanism to collect soil vapor at a later time.

“The analysis could be mailed back to a central laboratory or it could just be done in a mobile laboratory setting.

“If detection has occurred and has been verified, you can look at the data from the various probes. Keep in mind the probes are spaced every 20 feet along the line. You could have multiple lines in that trench. But you can look at the probes and data concentrations and you can say the point of highest concentration often leads you to the location of the source. So the higher the concentration, the closer the source. Sometimes we’re asked to go in and do additional pinpointing. But very typically, you can pinpoint these leaks down to three to 10 feet. Probes of highest concentration show the vicinity of the leak source.”

He said facility applications include: airports, military installations, power plants, refineries, and bulk storage terminals.   ♦

Hide comments

Comments

  • Allowed HTML tags: <em> <strong> <blockquote> <br> <p>

Plain text

  • No HTML tags allowed.
  • Web page addresses and e-mail addresses turn into links automatically.
  • Lines and paragraphs break automatically.
Publish