api 1169 part 49 cfr

Recommended practice for basic inspection requirements - new pipeline construction49 CFR-192 The Code of Federal RegulationsTransportation of Natural and Other Gas By Pipeline Subpart G, J, N.2014-OctoberMy Self Study Exam Preparatory Notes

Charlie Chong/ Fion Zhang

49


Expert at Works


Make it easy to read for foreign candidates like myself for API ICP exam:


Experts at Works

Fion Zhang2014/October

http://meilishouxihu.blog.163.com/



THE REFERENCES BELOW WILL BE AVAILABLE TO APPLICANTS ON THE COMPUTER SCREEN DURING THE EXAM:

Code of Federal Regulations (CFR)

• 29 CFR 1910, Occupational Safety and Health Standards,Subparts H Article 119, Subpart I (Excluding Subpart I Appendices) and Subpart J Articles 145-147 (Excluding Appendices)


• 29 CFR 1926, Safety and Health Regulations for Construction:Subpart C Articles 20-29 and 32-35, Subpart D Article 62 (Excluding Appendices), Subpart F Article 152, Subpart H Articles 250-251, Subpart J Article 351-354, Subpart L Article 451, Subpart M Article 500-501, Subpart O 600, Subpart P, Subpart U Article 900-902 and 914 and Subpart CC Article 1417.


• 40 CFR 112, Oil Pollution Prevention, Subpart A• 40 CFR 122, EPA Administered Permit


• 40 CFR 112, Oil Pollution Prevention, Subpart A• 40 CFR 122, EPA Administered Permit Programs: The National Pollutant

Discharge Elimination System: Subpart A

49 CFR 192, Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards: Subparts G, J & N

49 CFR 195, Transportation of Hazardous Liquids by Pipeline: Subpart D and Subpart E


Environmental Protection Agency (EPA), National Pollutant Discharge Elimination System General Permit for Discharges from Construction Activities 2012


49 CFR - Transportation

http://www.49cfr.info/index.html

http://www.law.cornell.edu/cfr/text/49

At works


Priority in the text

(a), (b)..... (1), (2)….. (i), (ii)….. (A), (B)…..



49 CFR 192 Subpart G, J, N.Transportation of Natural and Other Gas By Pipeline: Minimum Federal Safety Standards

THIS DOCUMENT CONTAINS ONLY THE SECTIONS NEEDED FOR THE API 1169 ICP EXAMSFormatted for My Self Study Exam Preparatory Notes


Subpart G -General Construction Requirements for Transmission Lines and Mains

§192.301 Scope. This subpart prescribes minimum requirements for constructing transmission lines and mains.

§192.303 Compliance with specifications or standards. Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part.

Keywords:■ Minimum;■ Compliance with specifications;■ Specifications Consistence with 49CFR;


12333Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part.Keywords:

Compliance with specifications or standards; Specifications and standards in consistence with 49CFR;


§192.305 Inspection: General. Each transmission line or main must be inspected to ensure that it is constructed in accordance with this part.

§192.307 Inspection of materials. Each length of pipe and each other component must be visually inspected at the site of installation to ensure that it has not sustained any visually determinable damage that could impair its serviceability.

§192.309 Repair of steel pipe. (a) Each imperfection or damage that impairs the serviceability of a length of steel pipe must be repaired or removed. If a repair is made by grinding, the remaining wall thickness must at least be equal to either:

(1) The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or

(2) The nominal wall thickness required for the design pressure of the pipeline.


DiscussionTopic: Differentiate the following:

(1) The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or



(2) A dent that affects the longitudinal weld or a circumferential weld.

(3) In pipe to be operated at a pressure that produces a hoop stress of 40 percent or more of SMYS, a dent that has a depth of:

(i) More than ¼ inch (6.4 millimeters) in pipe 12 ¾ inches (324 millimeters) or less in outer diameter; or

(ii) More than 2 percent of the nominal pipe diameter in pipe over 12 ¾inches (324 millimeters) in outer diameter.

For the purpose of this section a “dent” is a depression that produces a gross disturbance in the curvature of the pipe wall without reducing the pipe-wall thickness. The depth of a dent is measured as the gap between the lowest point of the dent and a prolongation of the original contour of the pipe.


(c) Each arc burn on steel pipe to be operated at a pressure that produces a hoop stress of 40 percent, or more, of SMYS must be repaired or removed. If a repair is made by grinding, the arc burn must be completely removed and the remaining wall thickness must be at least equal to either:

(1) The minimum wall thickness required by the tolerances in the specification to which the pipe was manufactured; or


(d) A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out.

(e) Each gouge, groove, arc burn, or dent that is removed from a length of pipe must be removed by cutting out the damaged portion as a cylinder.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-88, 64 FR 69664, Dec. 14, 1999]


Arc Burn


Arc Strike- Arc Burn

http://kriznoy.wordpress.com/2013/08/30/arc-strike/



http://met-tech.com/failure-analysis-of-ball-bearings.html


Discussion 1Topic: How to ensure total removal of Arc Burn.

§192.309 (c) Each arc burn on steel pipe to be operated at a pressure that produces a hoop stress of 40 percent, or more, of SMYS must be repaired or removed. If a repair is made by grinding, the arc burn must be completely removed and the remaining wall thickness must be at least equal to either:

Hints: Nitric acid 硝酸

Topic: Defines; a gouge, groove, arc burn and dent.

(d) A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out.


Discussion 2Topic: Why is arc strike is an important issue in pipeline welding?

§192.309 (e) Each gouge, groove, arc burn, or dent that is removed from alength of pipe must be removed by cutting out the damaged portion as a cylinder.

Hint: High strength API 5LX material grade.


APL

5LX

Pipe

Tec

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al In

form

atio

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§192.311 Repair of plastic pipe. Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.

[Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]

Keywords:

■ Plastid Pipe


Plastid Pipeline

http://www.chings.co.nz/operations_pe_welding-1.html


Plastid Pipe


§192.313 Bends and elbows. Each field bend in steel pipe, other than a wrinkle bend made in accordance with §192.315, must comply with the following:

(1) A bend must not impair the serviceability of the pipe.

(2) Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage.

Keywords:

■ Wrinkle bend■ Buckling■ Crack


Bend & Wrinkle Bend


(3) On pipe containing a longitudinal weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless:

(i) The bend is made with an internal bending mandrel; or

(ii) The pipe is 12 inches (305 millimeters) or less in outside diameter or has a diameter to wall thickness ratio less than 70.

Keywords: longitudinal weld must be as near as practicable to the neutral axis of the

bend Internal bend mandrel Diameter/ Wall thickness ratio ˂ 70


Internal bending mandrel


(b) Each circumferential weld of steel pipe which is located where the stress during bending causes a permanent deformation in the pipe must be nondestructively tested either before or after the bending process.

(c) Wrought-steel welding elbows and transverse segments of these elbows may not be used for changes in direction on steel pipe that is 2 inches (51 millimeters) or more in diameter unless the arc length, as measured along the crotch, is at least 1 inch (25 millimeters).

[Amdt. No. 192-26, 41 FR 26018, June 24, 1976, as amended by Amdt. 192-29, 42 FR 42866, Aug. 25, 1977; Amdt. 192-29, 42 FR 60148, Nov. 25, 1977; Amdt. 192-49, 50 FR 13225, Apr. 3, 1985; Amdt. 192-85, 63 FR 37503, July 13, 1998]


DiscussionTopic: What is Wrought-steel welding elbows and transverse segments?

§ §192.313 (c) Wrought-steel (锻的/加工的) welding elbows (mitered bend?)and transverse segments of these elbows may not be used for changes in direction on steel pipe that is 2 inches (51 millimeters) or more in diameter unless the arc length, as measured along the crotch, is at least 1 inch (25 millimeters).


DiscussionTopic: How to perform NDT on the field pipe bended.

§ §192.313 (b) Each circumferential weld of steel pipe which is located where the stress during bending causes a permanent deformation in the pipe must be nondestructively tested either before or after the bending process.


§192.315 Wrinkle bends in steel pipe.

(a)A wrinkle bend may not be made on steel pipe to be operated at apressure that produces a hoop stress of 30 percent, or more, of SMYS.

(b)Each wrinkle bend on steel pipe must comply with the following:

(1)The bend must not have any sharp kinks.(2)When measured along the crotch of the bend, the wrinkles must be a

distance of at least one pipe diameter. (3)On pipe 16 inches (406 millimeters) or larger in diameter, the bend may

not have a deflection of more than 1 ½° for each wrinkle. (4)On pipe containing a longitudinal weld the longitudinal seam must be as

near as practicable to the neutral axis of the bend.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]


Wrinkle bends


§192.317 Protection from hazards. (a)The operator must take all practicable steps to protect each transmission

line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads. In addition, the operator must take all practicable steps to protect offshore pipelines from damage by mud slides, water currents, hurricanes, ship anchors, and fishing operations.

(b)Each aboveground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades.

(c) Pipelines, including pipe risers, on each platform located offshore or in inland navigable waters must be protected from accidental damage by vessels.

[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976, as amended by Amdt. 192-78, 61 FR 28784, June 6, 1996]


Remark: Each aboveground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades.


Subsea Pipeline Trencher


Subsea Pull Trencher



http://www.geocean.fr/2014/02/17/kalinda-shallow-water-pipelay-barge-support-mcdermott-safaniya-field/


Inland Pipeline Trencher


§192.319 Installation of pipe in a ditch. (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.

(b)When a ditch for a transmission line or main is backfilled, it must be backfilled in a manner that:

(1)Provides firm support under the pipe; and

(2)Prevents damage to the pipe and pipe coating from equipment or from the backfill material.


Pipe Bending: Pipeline operating at 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.


Field Pipe Bending


§192.321 Installation of plastic pipe. (a)Plastic pipe must be installed below ground level except as provided by

paragraphs (g) and (h) of this section.

(b)Plastic pipe that is installed in a vault (库) or any other below grade enclosure must be completely encased in gas-tight metal pipe and fittings that are adequately protected from corrosion.

(c) Plastic pipe must be installed so as to minimize shear or tensile stresses.

(d) Thermoplastic pipe that is not encased must have a minimum wall thickness of 0.090 inch (2.29 millimeters), except that pipe with an outside diameter of 0.875 inch (22.3 millimeters) or less may have a minimum wall thickness of 0.062 inch (1.58 millimeters).


(e)Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wiremay not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means

(f) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. The leading end of the plastic must be closed before insertion.


(g)Uncased plastic pipe may be temporarily installed above ground level under the following conditions:

(1)The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less.

(2)The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage.

(3)The pipe adequately resists exposure to ultraviolet light and high and low temperatures.

Keywords:

Period: Manufacturer recommendation or 2 years Maximum Damages from external mechanical source: Unlikely Damages from environments: UV, high & low temperature.


h) Plastic pipe may be installed on bridges provided that it is:

(1) Installed with protection from mechanical damage, such as installation in a metallic casing;

(2)Protected from ultraviolet radiation; and

(3)Not allowed to exceed the pipe temperature limits specified in §192.123.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003; Amdt. 192-94, 69 FR 32895, June 14, 2004]


§192.323 Casing. Each casing used on a transmission line or main under a railroad or highway must comply with the following:

(a)The casing must be designed to withstand the superimposed loads.

(b) If there is a possibility of water entering the casing, the ends must be sealed.

(c) If the ends of an unvented casing are sealed and the sealing is strong enough to retain the maximum allowable operating pressure of the pipe, the casing must be designed to hold this pressure at a stress level of not more than 72 percent of SMYS.

(d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing.


Road & Highway Crossing


Road & Highway Crossing - Open Ends


Pipeline Casing for Crossing


Pipeline Casing for Crossing- Vented and un-vented

http://www.farwestcorrosion.com/casing-spacers-seals/casing-fill/suggested-pipeline-casing-standard/


§192.325 Underground clearance. (a)Each transmission line must be installed with at least 12 inches (305

millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.

(b)Each main must be installed with enough clearance from any otherunderground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures.

(c) In addition to meeting the requirements of paragraph (a) or (b) of this section, each plastic transmission line or main must be installed with sufficient clearance, or must be insulated, from any source of heat so as to prevent the heat from impairing the serviceability of the pipe.

(d)Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in §192.175(b).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]


DiscussionTopic: What is this?

§192.325 (d) Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in §192.175(b).

Pipe-type? Bottle-type holder?


§192.327 Cover. (a)Except as provided in paragraphs (c), (e), (f), and (g) of this section, each

buried transmission line must be installed with a minimum cover as follows:

(b) Except as provided in paragraphs (c) and (d) of this section, each buried main must be installed with at least 24 inches (610 millimeters) of cover.

(c) Where an underground structure prevents the installation of a transmission line or main with the minimum cover, the transmission line or

main may be installed with less cover if it is provided with additional protection to withstand anticipated external loads.

24 (610) 36 (914) Drainage ditches of public roads and railroad crossings

24 (610) 36 (914) Class 2, 3, and 4 locations

18 (457) 30 (762) Class 1 locations

Inches (Millimeters)

Consolidated rock Normal soil Location


(d) A main may be installed with less than 24 inches (610 millimeters) of cover if the law of the State or municipality:

(1)Establishes a minimum cover of less than 24 inches (610 millimeters); (2)Requires that mains be installed in a common trench with other utility lines;

and (3)Provides adequately for prevention of damage to the pipe by external

forces.


Pipeline Covers


Pipeline Covers- Trench Breaker

http://huckbody.com/?page_id=1088


Pipeline Covers – Consolidated Rock


Pipeline Covers


Pipeline Covers- Main


(e) Except as provided in paragraph (c) of this section, all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches (610 millimeters) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices).

Keywords:Navigable River Crossing Covers:

Soil: 48 inches minimum Consolidated rock: 24 inches minimum


Navigable River Crossing Covers


River Crossing Covers- Non Navigable River


(f) All pipe installed offshore, except in the Gulf of Mexico and its inlets, under water not more than 200 feet (60 meters) deep, as measured from the mean low tide, must be installed as follows:

(1)Except as provided in paragraph (c) of this section, pipe under water less than 12 feet (3.66 meters) deep, must be installed with a minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457 millimeters) in consolidated rock between the top of the pipe and the natural bottom.

(2)Pipe under water at least 12 feet (3.66 meters) deep 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.

Keywords: Offshore Pipeline CoversWater depth < 12 feet: 36 inches minimum coverWater depth ≥ 12 feet: top of the pipe below natural bottom


(g) All pipelines installed under water in the Gulf of Mexico and its inlets, as defined in §192.3, must be installed in accordance with §192.612(b)(3).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, Aug. 16, 1976; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-98, 69 FR 48406, Aug. 10, 2004]


Gulf of Mexico


Offshore Pipeline Covers- Heaps or BucklingPipe under water at least 12 feet (3.66 meters) deep 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.


Offshore Pipeline CoversPipe under water at least 12 feet (3.66 meters) deep 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.



https://www.nord-stream.com/press-info/images/supervising-of-concrete-coating-process-at-eupec-concrete-weight-coating-plant-in-mukran-germany-2779/?page=20


Offshore Lay Barge – Non self navigating


Offshore Lay Barge with support vessels


Offshore Pipeline Barge



http://www.cnoocengineering.com/en/single_news_content.aspx?news_id=12343


Offshore Pipeline Trencher


Offshore Pipeline Mats


§192.328 Additional construction requirements for steel pipe using alternative maximum allowable operating pressure. For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure calculated under §192.620, a segment must meet the following additional construction requirements. Records must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:


(1) All girth welds on a new pipeline segment must be non‐destructively examined in accordance with §192.243(b) and (c).

(b) Girth welds

(ii) Performed by an individual with the knowledge, skills, and ability to assure effective coating application.

(i) Equivalent to that required under §192.112(f)(3) for pipe; and

(2) The quality assurance plan for applying and testing field applied coating to girth welds must be:

(1) The construction of the pipeline segment must be done under a quality assurance plan addressing pipe inspection, hauling and stringing, field bending, welding, non‐destructive examination of girth welds, applying and testing field applied coating, lowering of the pipeline into the ditch, padding and backfilling, and hydrostatic testing.

(a) Quality assurance

The pipeline segment must meet this additional construction requirement:

To address this construction issue:


(1) The pipeline segment must not have experienced failures indicative of systemic material defects during strength testing, including initial hydrostatic testing. A root cause analysis, including metallurgical examination of the failed pipe, must be performed for any failure experienced to verify that it is not indicative of a systemic concern. The results of this root cause analysis must be reported to eachPHMSA pipeline safety regional office where the pipe is in service at least 60 days prior to operating at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has

(d) Initial strength testing

(2) In areas where deep tilling or other activities could threaten the pipeline, the top of the pipeline must be installed at least one foot below the deepest expected penetration of the soil.

(1) Notwithstanding any lesser depth of cover otherwise allowed in §192.327, there must be at least 36 inches (914 millimeters) of cover or equivalent means to protect the pipeline from outside force damage.

(c) Depth of cover


(1) For a new pipeline segment, the construction must address the impacts of induced alternating current from parallel electric transmission lines and other known sources of potential interference with corrosion control.

(e) Interference currents

[72 FR 62176, Oct. 17, 2008]


Tilling Soil


PHMSA- U.S. Department of Transportation (DOT)Pipeline and Hazardous MaterialsSafety Administration


Tilling Soil


Discussion Topic: What is §192.620

Answer: Read http://www.gpo.gov/fdsys/pkg/CFR-2009-title49-vol3/pdf/CFR-2009-title49-vol3-sec192-620.pdf

1. What is the alternative MAOP Rule?The alternate MAOP Rule was promulgated (颁布) by PHMSA to allow certain gas transmission pipelines to operate at higher pressures and pipeline stress levels than regulations previously allowed if certain conditions are met that ensure an adequate margin of safety. By allowing pipelines to operate at higher pressures and stress levels, greater efficiencies and gas product throughput can be achieved (73 FR 62148). ………& more…

More on http://primis.phmsa.dot.gov/maop/faqs.htm


Subpart J -Test Requirements

§192.501 Scope. This subpart prescribes minimum leak-test and strength-test requirements for

pipelines.

§192.503 General requirements. (a)No person may operate a new segment of pipeline, or return to service a

segment of pipeline that has been relocated or replaced, until –

(1) It has been tested in accordance with this subpart and §192.619 to substantiate the maximum allowable operating pressure; and

(2)Each potentially hazardous leak has been located and eliminated.


(b) The test medium must be liquid, air, natural gas, or inert gas that is –

(1)Compatible with the material of which the pipeline is constructed; (2)Relatively free of sedimentary materials; and (3)Except for natural gas, nonflammable.

(c) Except as provided in §192.505(a), if air, natural gas, or inert gas is used as the test medium, the following maximum hoop stress limitations apply:

40 30 4

50 30 3

75 30 2

80 80 1

Air or inert gas Natural gas

Maximum hoop stress allowed as percentage of SMYS Class location


(d) Each joint used to tie in a test segment of pipeline is excepted from the specific test requirements of this subpart, but each non-welded joint must be leak tested at not less than its operating pressure.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-60, 53 FR 36029, Sept. 16, 1988; Amdt. 192-60A, 54 FR 5485, Feb. 3, 1989]


DiscussionTopic: The quoted Maximum hoop stress allowed as % of SMYS, is it meant for testing?

80 80 1

75 30 2

Air or inert gas Natural gas

Maximum hoop stress allowed as percentage of SMYS Class location


§ 192.5 Class locations. (a)This section classifies pipeline locations for purposes of this part. The

following criteria apply to classifications under this section.

(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) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.

220 yards

220 yards

1 mile/ 1.6 KM

pipeline

http://www.law.cornell.edu/cfr/text/49/192.5


(b) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows:

(1) A Class 1 location is:

(i) An offshore area; or (ii) Any class location unit that has 10 or fewer buildings intended for human

occupancy.


(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy.

(3) A Class 3 location is:

(i) Any class location unit that has 46 or more buildings intended for human occupancy; or

(i) 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.)


(4)A Class 4 location is any class location unit where buildings with four (4)or more stories above ground are prevalent.

(c) The length of Class locations 2, 3, and 4 may be adjusted as follows:

(1)A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground.

(2)When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster.

[Amdt. 192-78, 61 FR 28783, June 6, 1996; 61 FR 35139, July 5, 1996, as amended by Amdt. 192-85, 63 FR 37502, July 13, 1998]


§192.505 Strength test requirements for steel pipeline to operate at a hoop stress of 30 percent or more of SMYS. (a) Except for service lines, each segment of a steel pipeline that is to operate at a hoop stress of 30 percent or more of SMYS must be strength tested in accordance with this section to substantiate the proposed maximum allowable operating pressure.

In addition, in a Class 1 or Class 2 location, if there is a building intended for human occupancy within 300 feet (91 meters) of a pipeline, a hydrostatic test must be conducted to a test pressure of at least 125 percent of maximum operating pressure on that segment of the pipeline within 300 feet (91 meters) of such a building, but in no event may the test section be less than 600 feet (183 meters) unless the length of the newly installed or relocated pipe is less than 600 feet (183 meters).

However, if the buildings are evacuated while the hoop stress exceeds 50 percent of SMYS, air or inert gas may be used as the test medium.


(b) In a Class 1 or Class 2 location, each compressor station regulator station, and measuring station, must be tested to at least Class 3 location test requirements.

(c) Except as provided in paragraph (e) of this section, the strength test must be conducted by maintaining the pressure at or above the test pressure for at least 8 hours.

(d) If a component other than pipe is the only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies that-

(1)The component was tested to at least the pressure required for the pipeline to which it is being added;

(2)The component was manufactured under a quality control system that ensures that each item manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or

(3)The component carries a pressure rating established through applicable ASME/ANSI, MSS specifications, or by unit strength calculations as described in §192.143.


(e) For fabricated units and short sections of pipe, for which a post installation test is impractical, a preinstallation strength test must be conducted by maintaining the pressure at or above the test pressure for at least 4 hours.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-94, 69 FR 32895, June 14, 2004; Amdt. 195-94, 69 FR 54592, Sept. 9, 2004]


Keywords: Testing pressure & Medium

Operating condition: 30% of SMYS; Area Class: 1 or 2; Occupancy criteria: a building within 300 feet within pipe center line; Testing requirements: Hydrostatic testing at 125% of MOP.

Exclusion: However, if the buildings are evacuated while the hoop stress exceeds 50 percent of SMYS, air or inert gas may be used as the test medium.

Question: Area Class 2 & 4 what are the testing requirements?


Keywords: Test Duration at rated pressure

Operating condition: 30% of SMYS;

the strength test must be conducted by maintaining the pressure at or above the test pressure for at least 8 hours.

For fabricated units and short sections of pipe, for which a post installation test is impractical, a pre-installation strength test must be conducted by maintaining the pressure at or above the test pressure for at least 4 hours.


§192.505 However, if the buildings are evacuated while the hoop stress exceeds 50 percent of SMYS, air or inert gas may be used as the test medium.

http://portolaplanet.com/2012/06/pge-pipeline-testing-keeps-the-portola-safe/


§192.507 Test requirements for pipelines to operate at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage. Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in accordance with the following:

(a)The pipeline operator must use a test procedure that will ensure discovery of all potentially hazardous leaks in the segment being tested.

(b) If, during the test, the segment is to be stressed to 20 percent or more of SMYS and natural gas, inert gas, or air is the test medium -

(1)A leak test must be made at a pressure between 100 p.s.i. (689 kPa) gage and the pressure required to produce a hoop stress of 20 percent of SMYS; or

(2)The line must be walked to check for leaks while the hoop stress is held at approximately 20 percent of SMYS.


(c) The pressure must be maintained at or above the test pressure for at least 1 hour.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan.21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]


§192.509 Test requirements for pipelines to operate below 100 p.s.i. (689 kPa) gage. Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated below 100 p.s.i. (689 kPa) gage must be leak tested in accordance with the following:

(a)The test procedure used must ensure discovery of all potentiallyhazardous leaks in the segment being tested.

(b)Each main that is to be operated at less than 1 p.s.i. (6.9 kPa) gage must be tested to at least 10 p.s.i. (69 kPa) gage and each main to be operated at or above 1 p.s.i. (6.9 kPa) gage must be tested to at least 90 p.s.i. (621 kPa) gage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan.21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]


§192.511 Test requirements for service lines. (a)Each segment of a service line (other than plastic) must be leak tested in

accordance with this section before being placed in service. If feasible, the service line connection to the main must be included in the test; if not feasible, it must be given a leakage test at the operating pressure when placed in service.

(b)Each segment of a service line (other than plastic) intended to be operated at a pressure of at least 1 p.s.i. (6.9 kPa) gage but not more than 40 p.s.i. (276 kPa) gage must be given a leak test at a pressure of not less than 50 p.s.i. (345 kPa) gage.

(c) Each segment of a service line (other than plastic) intended to be operated at pressures of more than 40 p.s.i. (276 kPa) gage must be tested to at least 90 p.s.i. (621 kPa) gage, except that each segment of a steel service line stressed to 20 percent or more of SMYS must be tested in accordance with §192.507 of this subpart.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-74, 61 FR 18517, Apr. 26, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998]


§192.513 Test requirements for plastic pipelines. (a)Each segment of a plastic pipeline must be tested in accordance with this

section. (b)The test procedure must insure discovery of all potentially hazardous leaks

in the segment being tested. (c) The test pressure must be at least 150 percent of the maximum operating

pressure or 50 p.s.i. (345 kPa) gage, whichever is greater. However, the maximum test pressure may not be more than three times the pressure determined under §192.121, at a temperature not less than the pipe temperature during the test.

(d)During the test, the temperature of thermoplastic material may not be more than 100 °F (38 °C), or the temperature at which the material's long-term hydrostatic strength has been determined under the listed specification, whichever is greater.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-77, 61 FR 27793, June 3, 1996; 61 FR 45905, Aug. 30, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998]


§192.515 Environmental protection and safety requirements. (a) In conducting tests under this subpart, each operator shall insure that

every reasonable precaution is taken to protect its employees and the general public during the testing. Whenever the hoop stress of the segment of the pipeline being tested will exceed 50 percent of SMYS, the operator shall take all practicable steps to keep persons not working on the testing operation outside of the testing area until the pressure is reduced to or below the proposed maximum allowable operating pressure.

(b)The operator shall insure that the test medium is disposed of in a manner that will minimize damage to the environment.


§192.517 Records. (a)Each operator shall make, and retain for the useful life of the pipeline, a

record of each test performed under §§192.505 and 192.507. The record must contain at least the following information:

(1)The operator's name, the name of the operator's employee responsible for making the test, and the name of any test company used.

(2)Test medium used. (3)Test pressure. (4)Test duration. (5)Pressure recording charts, or other record of pressure readings.(6)Elevation variations, whenever significant for the particular test. (7)Leaks and failures noted and their disposition.

(b) Each operator must maintain a record of each test required by §§192.509, 192.511, and 192.513 for at least 5 years.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]


Pipeline Testing


Pipeline Testing

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Pipeline Testing


Subpart N –Qualification of Pipeline PersonnelSOURCE: Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, unless otherwise

noted.

§192.801 Scope. (a)This subpart prescribes the minimum requirements for operator

qualification of individuals performing covered tasks on a pipeline facility.

(a)For the purpose of this subpart, a covered task is an activity, identified by the operator, that:

(1) Is performed on a pipeline facility; (2) Is an operations or maintenance task; (3) Is performed as a requirement of this part; and (4) Affects the operation or integrity of the pipeline.


Subpart N –Qualification of Pipeline Personnel SOURCE: Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, unless otherwise noted. §192.801 Scope. (a)This subpart prescribes the minimum requirements for operator

qualification of individuals performing covered tasks on a pipeline facility. (b)For the purpose of this subpart, a covered task is an activity, identified by

the operator, that:

(1) Is performed on a pipeline facility; (2) Is an operations or maintenance task; (3) Is performed as a requirement of this part; and (4) Affects the operation or integrity of the pipeline.


§192.803 Definitions.

Abnormal operating condition means a condition identified by the operator that may indicate a malfunction of a component or deviation from normal operations that may: (a) Indicate a condition exceeding design limits; or (b) Result in a hazard(s) to persons, property, or the environment.

Evaluation means a process, established and documented by the operator, to determine an individual's ability to perform a covered task by any of the following: (a) Written examination; (b) Oral examination; (c) Work performance history review; (d) Observation during:

(1) Performance on the job, (2) On the job training, or (3) Simulations;

(e) Other forms of assessment.


Qualified means that an individual has been evaluated and can: (a) Perform assigned covered tasks; and (b) Recognize and react to abnormal operating conditions.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 66 FR 43523, Aug. 20, 2001]

Keywords:(a) Perform assigned covered tasks; and (b) Recognize and react to abnormal operating conditions.


Keywords:Qualified means that an individual has been evaluated and can: (a) Perform assigned covered tasks; and (b) Recognize and react to abnormal operating conditions.


On the Job Training


§192.805 Qualification program. Each operator shall have and follow a written qualification program. The program shall include provisions to:

(a) Identify covered tasks; (b)Ensure through evaluation that individuals performing covered tasks are

qualified; (c) Allow individuals that are not qualified pursuant (按照) to this subpart to

perform a covered task if directed and observed by an individual that is qualified;

(d)Evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident as defined in Part 191;

(e)Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task;


(f) Communicate changes that affect covered tasks to individuals performing those covered tasks;

(g) Identify those covered tasks and the intervals at which evaluation of the individual's qualifications is needed;

(h)After December 16, 2004, provide training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities; and

(i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the Administrator or state agency has verified that it complies with this section.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-100, 70 FR 10335, Mar. 3, 2005]


Keywords:Provisions on evaluations of:Qualified personnel No longer qualified.

Training provision after December 16, 2004


§192.807 Recordkeeping. Each operator shall maintain records that demonstrate compliance with this subpart.

(a)Qualification records shall include:

(1) Identification of qualified individual(s); (2) Identification of the covered tasks the individual is qualified to perform; (3) Date(s) of current qualification; and (4) Qualification method(s).

(b) Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five years.


§192.809 General. (a)Operators must have a written qualification program by April 27, 2001. The

program must be available for review by the Administrator or by a state agency participating under 49 U.S.C. Chapter 601 if the program is under the authority of that state agency.

(b)Operators must complete the qualification of individuals performing covered tasks by October 28, 2002.

(c) Work performance history review may be used as a sole evaluationmethod for individuals who were performing a covered task prior to October 26, 1999.

(d)After October 28, 2002, work performance history may not be used as a sole evaluation method.

(e)After December 16, 2004, observation of on-the-job performance may not be used as the sole method of evaluation.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 66 FR 43524, Aug. 20, 2001; Amdt. 192-100, 70 FR 10335, Mar. 3, 2005]


Keywords: Work performance history review Observation of on-the-job performance


49 CFR-192 Numbers to be remembered

Some numbers to be remember – at

least knowing where to find them.


49CFR §192.309 (b) Repair of steel pipe.

(2) A dent that affects the longitudinal weld or a circumferential weld.

(3) In pipe to be operated at a pressure that produces a hoop stress of 40 percent or more of SMYS, a dent that has a depth of:

(i) More than ¼ inch (6.4 millimeters) in pipe 12 ¾ inches (324 millimeters) or less in outer diameter; or

(ii) More than 2 percent of the nominal pipe diameter in pipe over 12 ¾inches (324 millimeters) in outer diameter.

For the purpose of this section a “dent” is a depression that produces a gross disturbance in the curvature of the pipe wall without reducing the pipe-wall thickness. The depth of a dent is measured as the gap between the lowest point of the dent and a prolongation of the original contour of the pipe.


§192.319 Installation of pipe in a ditch. 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.


§192.325 Underground clearance. Each transmission line must be installed with at least 12 inches (305

millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.

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