Installation of Pipe in a Ditch [49 CFR 192.319]

(A)A. When installed in a ditch, each transmission line that is to be operated at a pressure producing a hoop stress of 20 percent or more of SMYS must be installed so that the pipe fits the ditch so as to minimize stresses and protect the pipe coating from damage. [49 CFR 192.319(a)]#

(B)B. When a ditch for a transmission line or main is backfilled, it must be backfilled in a manner that: [49 CFR 192.319(b)]#

(1)1. provides firm support under the pipe; and [49 CFR 192.319(b)(1)]#

(2)2. prevents damage to the pipe and pipe coating from equipment or from the backfill material. [49 CFR 192.319(b)(2)]#

(C)C. All offshore pipe in water at least 12 feet (3.7 meters) deep but not more than 200 feet (61 meters) deep, as measured from the mean low tide, except pipe in the Gulf of America and its inlets under 15 feet (4.6 meters) of water, must be installed so that the top of the pipe is below the natural bottom unless the pipe is supported by stanchions, held in place by anchors or heavy concrete coating, or protected by an equivalent means. Pipe in the Gulf of Mexico and its inlets under 15 feet (4.6 meters) of water must be installed so that the top of the pipe is 36 inches (914 millimeters) below the seabed for normal excavation or 18 inches (457 millimeters) for rock excavation. [49 CFR 192.319(c)]#

(D)D. Promptly after a ditch for an onshore steel transmission line is backfilled (if the construction project involves 1,000 feet or more of continuous backfill length along the pipeline), but not later than 6 months after placing the pipeline in service, the operator must perform an assessment to assess any coating damage and ensure integrity of the coating using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or other technology that provides comparable information about the integrity of the coating. Coating surveys must be conducted, except in locations where effective coating surveys are precluded by geographical, technical, or safety reasons. [49 CFR 192.319(d)]#

(E)E. An operator must notify PHMSA in accordance with §518 at least 90 days in advance of using other technology to assess integrity of the coating under Subsection D of this Section. [49 CFR 192.319(e)]#

(F)F. An operator of an onshore steel transmission pipeline must develop a remedial action plan and apply for any necessary permits within 6 months of completing the assessment that identified the deficiency. An operator must repair any coating damage classified as severe (voltage drop greater than 60 percent for DCVG or 70 dBµV for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by reference, see §507) within 6 months of the assessment, or as soon as practicable after obtaining necessary permits, not to exceed 6 months after the receipt of permits. [49 CFR 192.319(g)]#

(G)G. An operator of an onshore steel transmission pipeline must make and retain for the life of the pipeline records documenting the coating assessment findings and remedial actions performed under Subsections D - F of this Section. [49 CFR 192.319(g)]#

AUTHORITY NOTE: Promulgated in accordance with R.S. 30:501 et seq.#

HISTORICAL NOTE: Promulgated by the Department of Natural Resources, Office of Conservation, LR 9:233 (April 1983), amended LR 10:525 (July 1984), LR 20:446 (April 1994), LR 24:1310 (July 1998), LR 27:1542 (September 2001), LR 30:1246 (June 2004), LR 50:1250 (September 2024), amended by the Department of Conservation and Energy, Office of Enforcement, LR 51:1833 (November 2025).#