§195.3. What documents are incorporated by reference partly or wholly in this part? — Inbound Citations

Notwithstanding any requirement of the subpart which incorporates by reference an edition of a document listed in § 195.3, a metallic component other than pipe manufactured in accordance with any other edition of that document is qualified for use if—

(i) The yield strength determined by performing all of the tensile tests of API Spec 5L (incorporated by reference, see § 195.3) on randomly selected specimens with the following number of tests:

(a) Anticipated external loads (e.g., earthquakes, vibration, thermal expansion, and contraction) must be provided for in a pipeline system's design. Sections 401, 402, 403.3, and 403.9 of ASME B31.4 (incorporated by reference, see § 195.3) must be followed to provide for expansion and flexibility.

(d) Each valve must be both hydrostatically shell tested and hydrostatically seat tested without leakage to at least the requirements set forth in Section 11 of API Spec 6D (incorporated by reference, see § 195.3).

(a) Butt-welding type fittings must meet the marking, end preparation, and the bursting strength requirements of ASME/ANSI B16.9 or MSS SP-75 (incorporated by reference, see § 195.3).

(a) Except as provided in paragraphs (b) and (c) of this section, each new pipeline and each main line section of a pipeline where the line pipe, valve, fitting or other line component is replaced must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102 (incorporated by reference, see § 195.3).

Each closure to be installed in a pipeline system must comply with the 2007 ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1) (incorporated by reference, see § 195.3) and must have pressure and temperature ratings at least equal to those of the pipe to which the closure is attached.

(1) Shop-fabricated, vertical, cylindrical, closed top, welded steel tanks with nominal capacities of 90 to 750 barrels (14.3 to 119.2 m 3) and with internal vapor space pressures that are approximately atmospheric must be designed and constructed in accordance with API Spec 12F (incorporated by reference, see § 195.3) .

(c) A new computational pipeline monitoring (CPM) leak detection system or replaced component of an existing CPM system must be designed in accordance with the requirements in section 4.2 of API RP 1130 (incorporated by reference, see § 195.3) and any other applicable design criteria in that standard.

(1) For tanks designed for approximate atmospheric pressure, constructed of carbon and low alloy steel, welded or riveted, and non-refrigerated; and for tanks built to API Std 650 (incorporated by reference, see § 195.3) or its predecessor Standard 12C; repair, alteration; and reconstruction must be in accordance with API Std 653 (except section 6.4.3) (incorporated by reference, see § 195.3).

(a) In a pipeline operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by railroad unless the transportation is performed in accordance with API RP 5L1 (incorporated by reference, see § 195.3).

(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5 (except for Note 2 in section 5.4.2.2), section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 195.3), or Section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see § 195.3). The quality of the test welds used to qualify the welding procedures must be determined by destructive testing.

(a) Each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see § 195.3), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC), (incorporated by reference, see § 195.3) except that a welder or welding operator qualified under an earlier edition than listed in § 195.3, may weld but may not requalify under that earlier edition.

(b) The acceptability of a weld is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see § 195.3). Appendix A of API Std 1104 may not be used to accept cracks.

(1) For tanks built to API Spec 12F, API Std 620, and others (such as API Std 650 (or its predecessor Standard 12C)), the installation of impoundment must be in accordance with the following sections of NFPA 30 (incorporated by reference, see § 195.3);

(i) Impoundment around a breakout tank must be installed in accordance with section 22.11.2; and

(ii) Impoundment by drainage to a remote impounding area must be installed in accordance with section 22.11.1.

(a) For aboveground breakout tanks built to API Spec 12F (incorporated by reference, see § 195.3) and first placed in service after October 2, 2000, pneumatic testing must be performed in accordance with section 5.3 of API Spec 12F.

(a) After October 2, 2000, protection provided against ignitions arising out of static electricity, lightning, and stray currents during operation and maintenance activities involving aboveground breakout tanks must be in accordance with API RP 2003 (incorporated by reference, see § 195.3), unless the operator notes in the procedural manual (§ 195.402(c)) why compliance with all or certain provisions of API RP 2003 is not necessary for the safety of a particular breakout tank.

(i) Eighty percent of the first test pressure that produces yield under section N5.0 of appendix N of ASME B31.8 (incorporated by reference, see § 195.3), reduced by the appropriate factors in §§ 195.106 (a) and (e); or

(c) Aboveground breakout tanks that are constructed or significantly altered according to API Std 2510 (incorporated by reference, see § 195.3) after October 2, 2000, must have an overfill protection system installed according to API Std 2510, section 7.1.2. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API Std 2350 (incorporated by reference, see § 195.3). However, an operator need not comply with any part of API Std 2350 for a particular breakout tank if the operator describes in the manual required by § 195.402 why compliance with that part is not necessary for safety of the tank.

(b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see § 195.3). However, if structural conditions prevent access to the tank bottom, its integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3). The risk-based internal inspection procedures in API Std 653, section 6.4.3 cannot be used to determine the internal inspection interval.

(1) Operators who established internal inspection intervals based on risk-based inspection procedures prior to March 6, 2015 must re-establish internal inspection intervals based on API Std 653, section 6.4.2 (incorporated by reference, see § 195.3).

(i) If the internal inspection interval was determined by the prior risk-based inspection procedure using API Std 653, section 6.4.3 and the resulting calculation exceeded 20 years, and it has been more than 20 years since an internal inspection was performed, the operator must complete a new internal inspection in accordance with § 195.432(b)(1) by January 5, 2017.

(ii) If the internal inspection interval was determined by the prior risk-based inspection procedure using API Std 653, section 6.4.3 and the resulting calculation was less than or equal to 20 years, and the time since the most recent internal inspection exceeds the re-established inspection interval in accordance with § 195.432(b)(1), the operator must complete a new internal inspection by January 5, 2017.

(iii) If the internal inspection interval was not based upon current engineering and operational information (i.e., actual corrosion rate of floor plates, actual remaining thickness of the floor plates, etc.), the operator must complete a new internal inspection by January 5, 2017 and re-establish a new internal inspection interval in accordance with § 195.432(b)(1).

(2) [Reserved]

(a) Each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute's (API) Recommended Practice (RP) 1162 (incorporated by reference, see § 195.3).

(c) Each computational pipeline monitoring (CPM) leak detection system installed on a hazardous liquid pipeline must comply with API RP 1130 (incorporated by reference, see § 195.3) in operating, maintaining, testing, record keeping, and dispatcher training of the system.

(1) Implement API RP 1165 (incorporated by reference, see § 195.3) whenever a SCADA system is added, expanded or replaced, unless the operator demonstrates that certain provisions of API RP 1165 are not practical for the SCADA system used;

(B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (incorporated by reference, see § 195.3) and PRCI PR-3-805 (R-STRENG) (incorporated by reference, see § 195.3).

(i) Testing the pipeline in accordance with ASME B31.8 (incorporated by reference, see § 195.3), Appendix N, to produce a stress equal to the yield strength; and

After October 2, 2000, when you install cathodic protection under § 195.563(a) to protect the bottom of an aboveground breakout tank of more than 500 barrels 79.49m3 capacity built to API Spec 12F (incorporated by reference, see § 195.3), API Std 620 (incorporated by reference, see § 195.3), API Std 650 (incorporated by reference, see § 195.3), or API Std 650's predecessor, Standard 12C, you must install the system in accordance with ANSI/API RP 651 (incorporated by reference, see § 195.3). However, you don't need to comply with API RP 651 when installing any tank for which you note in the corrosion control procedures established under § 195.402(c)(3) why complying with all or certain provisions of API RP 651 is not necessary for the safety of the tank.

Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3 in NACE SP 0169 (incorporated by reference, see § 195.3).

(2) Identify not more than 2 years after cathodic protection is installed, the circumstances in which a close-interval survey or comparable technology is practicable and necessary to accomplish the objectives of paragraph 10.1.1.3 of NACE SP 0169 (incorporated by reference, see § 195.3).

(d) After October 2, 2000, when you install a tank bottom lining in an aboveground breakout tank built to API Spec 12F (incorporated by reference, see § 195.3), API Std 620 (incorporated by reference, see § 195.3), API Std 650 (incorporated by reference, see § 195.3), or API Std 650's predecessor, Standard 12C, you must install the lining in accordance with API RP 652 (incorporated by reference, see § 195.3). However, you don't need to comply with API RP 652 when installing any tank for which you note in the corrosion control procedures established under § 195.402(c)(3) why compliance with all or certain provisions of API RP 652 is not necessary for the safety of the tank.

Under § 195.585, you may use the procedure in ASME/ANSI B31G (incorporated by reference, see § 195.3) or in PRCI PR-3-805 (R-STRENG) (incorporated by reference, see § 195.3) to determine the strength of corroded pipe based on actual remaining wall thickness. These procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations set out in the respective procedures.

(1) You must follow the requirements of NACE SP0502 (incorporated by reference, see § 195.3). Also, you must develop and implement a External Corrosion Direct Assessment (ECDA) plan that includes procedures addressing pre-assessment, indirect examination, direct examination, and post-assessment.

When conducting in-line inspection of pipelines required by this part, each operator must comply with the requirements and recommendations of API Std 1163, ASNT ILI-PQ, and NACE SP0102 (all incorporated by reference, see § 195.3). An in-line inspection may also be conducted using tethered or remote-control tools provided they generally comply with those sections of NACE SP0102 that are applicable.