Arkansas Administrative Code › Agency 126 - PUBLIC SERVICE COMMISSION › Division 01 - Pipeline Safety Section › Rule 126.01.09-001 - Arkansas Gas Pipeline Code

Current through Register Vol. 49, No. 6, June, 2024
SUBPART
			 I
REQUIREMENTS FOR CORROSION CONTROL
§ 192.451
Scope
This subpart prescribes minimum requirements for the protection
				of metallic pipelines from external, internal, and atmospheric
				corrosion.
§ 192.452
How does this subpart apply to converted pipelines and regulated onshore
			 gathering lines?
(a)
Converted
			 pipelines.
Notwithstanding the date the pipeline was installed or any
			 earlier deadlines for compliance, each pipeline which qualifies for use under
			 this part in accordance with § 192.14 must meet the requirements of this
			 subpart specifically applicable to pipelines installed before August 1, 1971,
			 and all other applicable requirements within 1 year after the pipeline is
			 readied for service. However, the requirements of this subpart specifically
			 applicable to pipelines installed after July 31, 1971, apply if the pipeline
			 substantially meets those requirements before it is readied for service or it
			 is a segment which is replaced, relocated, or substantially altered.
(b)
Regulated onshore gathering
			 lines.
For any regulated onshore gathering line under § 192.9
			 existing on April 14, 2006, that was not previously subject to this part, and
			 for any onshore gathering line that becomes a regulated onshore gathering line
			 under § 192.9 after April 14, 2006, because of a change in class location
			 or increase in dwelling density:
(1) The
			 requirements of this subpart specifically applicable to pipelines installed
			 before August 1, 1971, apply to the gathering line regardless of the date the
			 pipeline was actually installed; and
(2) The requirements of this subpart
			 specifically applicable to pipelines installed after July 31,1971, apply only
			 if the pipeline substantially meets those requirements.
§ 192.453
General
The corrosion control procedures required by §
				192.605(b)(2), including those for design, installation, operation and
				maintenance of cathodic protection systems, must be carried out by, or under
				the direction of, a person qualified by experience and training in pipeline
				corrosion control methods.
§
			 192.455
External Corrosion Control: Buried or Submerged
			 Pipelines Installed After July 31,1971
(a) Except as provided in paragraphs (b),
			 (c), and (f) of this section, each buried or submerged pipeline installed after
			 July 31,1971, must be protected against external corrosion, including the
			 following:
(1) It must have an external
			 protective coating meeting the requirements of § 192.461.
(2) It must have a cathodic protection system
			 designed to protect the pipeline in its entirety in accordance with this
			 subpart, installed and placed in operation within one year after completion of
			 construction.
(b) An
			 operator need not comply with paragraph (a) of this section, if the operator
			 can demonstrate by tests, investigation, or experience in the area of
			 application, including, as a minimum, soil resistivity measurements and tests
			 for corrosion accelerating bacteria, that a corrosive environment does not
			 exist. However, within 6 months after an installation made pursuant to the
			 preceding sentence, the operator shall conduct tests, including pipe-to-soil
			 potential measurements with respect to either a continuous reference electrode
			 or an electrode using close spacing, not to exceed 20 feet (6 meters), and soil
			 resistivity measurements at potential profile peak locations, to adequately
			 evaluate the potential profile along the entire pipeline. If the tests made
			 indicate that a corrosive condition exists, (he pipeline must be cathodically
			 protected in accordance with paragraph (a)(2) of this section.
(c) An operator need not comply with
			 paragraph (a) of this section, if the operator can demonstrate by tests,
			 investigation, or experience that:
(1) For a
			 copper pipeline, a corrosive environment does not exist; or
(2) For a temporary pipeline with an
			 operating period of service not to exceed 5 years beyond installation,
			 corrosion during the 5 year period of service of the pipeline will not be
			 detrimental to public safety.
(d) Notwithstanding the provisions of
			 paragraph (b) or (c) of this section, if a pipeline is externally coated, it
			 must be cathodically protected in accordance with paragraph (a)(2) of this
			 section.
(e) Aluminum may not be
			 installed in a buried or submerged pipeline if that aluminum is exposed to an
			 environment with a natural pH in excess of 8, unless tests or experience
			 indicates its suitability in the particular environment involved.
(f) This section does not apply to
			 electrically isolated, metal alloy fittings in plastic pipelines if:
(1) For the size fitting to be used, an
			 operator can show by tests, investigation, or experience in the area of
			 application, that adequate corrosion control is provided by the alloy
			 composition; and
(2) The fitting is
			 designed to prevent leakage caused by localized corrosion pitting.
§ 192.457
External Corrosion Control: Buried or Submerged Pipelines Installed
			 Before August 1,1971
(a) Except for
			 buried piping at compressor, regulator, and measuring stations, each buried or
			 submerged transmission line installed before August 1,1971, that has an
			 effective external coating must be cathodically protected along the entire area
			 that is effectively coated, in accordance with this subpart. For the purposes
			 of this subpart, a pipeline does not have an effective external coating if its
			 cathodic protection current requirements are substantially the same as if it
			 were bare. The operator shall make tests to determine the cathodic protection
			 current requirements.
(b) Except
			 for cast iron or ductile iron, each of the following buried or submerged
			 pipelines installed before August 1,1971, must be cathodically protected in
			 accordance with this subpart in areas in which active corrosion is found:
(1) Bare or ineffectively coated transmission
			 lines.
(2) Bare or coated pipes at
			 compressor, regulator, and measuring stations.
(3) Bare or coated distribution
			 lines.
§
			 192.459
External corrosion control: Examination of buried
			 pipeline when exposed
Whenever an operator has knowledge that any portion of a buried
				pipeline is exposed, the exposed portion, if bare or the coating is
				deteriorated, must be examined for evidence of external corrosion. If external
				corrosion requiring remedial action under §§ 192.483 through 192.489
				is found, the operator shall investigate circumferentially and longitudinally
				beyond the exposed portion (by visual examination, indirect method, or both) to
				determine whether additional corrosion requiring remedial action exists in the
				vicinity of the exposed portion.
§
			 192.461
External Corrosion Control: Protective
			 Coating
(a) Each external protective
			 coating, whether conductive or insulating, applied for the purpose of external
			 corrosion control must:
(1) Be applied on a
			 properly prepared surface;
(2) Have
			 sufficient adhesion to the metal surface to effectively resist underfilm
			 migration of moisture;
(3) Be
			 sufficiently ductile to resist cracking;
(4) Have sufficient strength to resist damage
			 due to handling and soil stress; and
(5) Have properties compatible with any
			 supplemental cathodic protection.
(b) Each external protective coating which is
			 an electrically insulating type must also have low moisture absorption and high
			 electrical resistance.
(c) Each
			 external protective coating must be inspected just prior to lowering the pipe
			 into the ditch and backfilling, and any damage detrimental to effective
			 corrosion control must be repaired.
(d) Each external protective coating must be
			 protected from damage resulting from adverse ditch conditions or damage from
			 supporting blocks.
(e) If coated
			 pipe is installed by boring, driving, or other similar methods, precautions
			 must betaken to minimize damage to the coating during installation.
§ 192.463
External
			 Corrosion Control: Cathodic Protection
(a) Each cathodic protection system required
			 by this subpart must provide a level of cathodic protection that complies with
			 one or more of the applicable criteria contained in Appendix D of this subpart.
			 If none of these criteria is applicable, the cathodic protection system must
			 provide a level of cathodic protection at least equal to that provided by
			 compliance with one or more of these criteria.
(b) If amphoteric metals are included in a
			 buried or submerged pipeline containing a metal of different anodic potential:
(1) The amphoteric metals must be
			 electrically isolated from the remainder of the pipeline and cathodically
			 protected; or
(2) The entire buried
			 or submerged pipeline must be cathodically protected at a cathodic potential
			 that meets the requirements of Appendix D of this part for amphoteric
			 metals.
(c) The amount
			 of cathodic protection must be controlled so as not to damage the protective
			 coating or the pipe.
§
			 192.465
External Corrosion Control: Monitoring
(a) Each pipeline that is under cathodic
			 protection must be tested at least once each calendar year, but with intervals
			 not exceeding 15 months, to determine whether the cathodic protection meets the
			 requirements of § 192.463. However, if tests at those intervals are
			 impractical for separately protected short sections of mains or transmission
			 lines, not in excess of 100 feet (30 meters), or separately protected service
			 lines, these pipelines may be surveyed on a sampling basis. At least 10 percent
			 of these protected structures, distributed over the entire system must be
			 surveyed each calendar year, with a different 10 percent checked each
			 subsequent year, so that the entire system is tested in each 10 year
			 period.
(b) Each cathodic
			 protection rectifier or other impressed current power source must be inspected
			 six times each calendar year, but with intervals not exceeding 2½
			 months, to insure that it is operating. Evidence of proper functioning may be
			 current output, normal power consumption, a signal indicating normal D.C.
			 power, or satisfactory electrical state of the protected piping.
(c) Each reverse current switch, each diode,
			 and each interference bond whose failure would jeopardize structure protection
			 must be electrically checked for proper performance six times each calendar
			 year, but with intervals not exceeding 2½ months. Each other
			 interference bond must be checked at least once each calendar year, but with
			 intervals not exceeding 15 months.
(d) Each operator shall take prompt remedial
			 action to correct any deficiencies indicated by the monitoring.
(e) After Hie initial evaluation required by
			 §§ 192.455(b) and (c) and 192.457(b), each operator must, not less
			 than every 3 years at intervals not exceeding 39 months, reevaluate its
			 unprotected pipelines and cathodically protect them in accordance with this
			 subpart in areas in which active corrosion is found. The operator must
			 determine the areas of active corrosion by electrical survey. However, on
			 distribution lines and where an electrical survey is impractical on
			 transmission lines, areas of active corrosion may be determined by other means
			 that include review and analysis of leak repair and inspection records,
			 corrosion monitoring records, exposed pipe inspection records, and the pipeline
			 environment. In this section:
(1)
Active corrosion
means continuing corrosion which, unless
			 controlled, could result in a condition that is detrimental to public
			 safety.
(2)
Electrical
			 survey
means a series of closely spaced pipe-to-soil readings over a
			 pipeline that are subsequently analyzed to identify locations where a corrosive
			 current is leaving the pipeline.
(3)
Pipeline environment
includes soil resistivity (high or low), soil moisture (wet or dry), soil
			 contaminants that may promote corrosive activity, and other known conditions
			 that could affect the probability of active corrosion.
§ 192.467
External
			 Corrosion Control: Electrical Isolation
(a) Each buried or submerged pipeline must be
			 electrically isolated from other underground metallic structures, unless the
			 pipeline and the other structures are electrically interconnected and
			 cathodically protected as a single unit.
(b) One or more insulating devices must be
			 installed where electrical isolation of a portion of a pipeline is necessary to
			 facilitate the application of corrosion control.
(c) Except for unprotected copper inserted in
			 ferrous pipe, each pipeline must be electrically isolated from metallic casings
			 that are a part of the underground system. However, if isolation is not
			 achieved because it is impractical, other measures must be taken to minimize
			 corrosion of the pipeline inside the casing.
(d) Inspection and electrical tests must be
			 made to assure that electrical isolation is adequate.
(e) An insulating device may not be installed
			 in an area where a combustible atmosphere is anticipated unless precautions are
			 taken to prevent arcing.
(f) Where
			 a pipeline is located in close proximity to electrical transmission tower
			 footings, ground cables or counterpoise, or in other areas where fault currents
			 or unusual risk of lightning may be anticipated, it must be provided with
			 protection against damage due to fault currents or lightning, and protective
			 measures must also be taken at insulating devices.
§ 192.469
External Corrosion
			 Control: Test Stations
Each pipeline under cathodic protection required by this
				subpart must have sufficient test stations or other contact points for
				electrical measurement to determine the adequacy of cathodic protection.
§ 192.471
External
			 Corrosion Control: Test Leads
(a) Each
			 test lead wire must be connected to the pipeline so as to remain mechanically
			 secure and electrically conductive.
(b) Each test lead wire must be attached to
			 the pipeline so as to minimize stress concentration on the pipe.
(c) Each bared test lead wire and bared
			 metallic area at point of connection to the pipeline must be coated with an
			 electrical insulating material compatible with the pipe coating and the
			 insulation on the wire.
§
			 192.473
External Corrosion Control: Interference
			 Currents
(a) Each operator whose
			 pipeline system is subjected to stray currents shall have in effect a
			 continuing program to minimize the detrimental effects of such
			 currents.
(b) Each impressed
			 current type cathodic protection system or galvanic anode system must be
			 designed and installed so as to minimize any adverse effects on existing
			 adjacent underground metallic structures.
§ 192.475
Internal Corrosion
			 Control: General
(a) Corrosive gas may
			 not be transported by pipeline, unless the corrosive effect of the gas on the
			 pipeline has been investigated and steps have been taken to minimize internal
			 corrosion.
(b) Whenever any pipe is
			 removed from a pipeline for any reason, the internal surface must be inspected
			 for evidence of corrosion. If internal corrosion is found:
(1) The adjacent pipe must be investigated to
			 determine the extent of internal corrosion;
(2) Replacement must be made to the extent
			 required by the applicable paragraphs of §§ 192.485, 192.487, or
			 192.489; and
(3) Steps must be
			 taken to minimize the internal corrosion.
(c) Gas containing more than 0.1 grain of
			 hydrogen sulfide per 100 cubic feet (2.32
			 milligrams/m3) at standard conditions may not be
			 stored in pipe-type or bottle-type holders.
§ 192.476
Internal Corrosion
			 Control: Design and Construction of Transmission line
(a)
Design and construction.
Except as provided in paragraph (b) of this section, each new transmission line
			 and each replacement of line pipe, valve, fitting, or other line component in a
			 transmission line must have features incorporated into its design and
			 construction to reduce the risk of internal corrosion. At a minimum, unless it
			 is impracticable or unnecessary to do so, each new transmission line or
			 replacement of line pipe, valve, fitting or other line component in a
			 transmission line must:
(1) Be configured to
			 reduce the risk that liquids will collect in the line;
(2) Have effective liquid removal features
			 whenever the configuration would allow liquids to collect; and
(3) Allow use of devices for monitoring
			 internal corrosion at locations with significant potential for internal
			 corrosion.
(b)
Exceptions to applicability.
The design and construction
			 requirements of paragraph (a) of this section do not apply to the following:
(1) Offshore pipeline; and
(2) Pipeline installed or line pipe, valve,
			 fitting or other line component replaced before May 23, 2007.
(c)
Change to existing
			 transmission line.
When an operator changes the configuration of a
			 transmission line, the operator must evaluate the impact of the change on
			 internal corrosion risk to the downstream portion of an existing onshore
			 transmission line and provide for removal of liquids and monitoring of internal
			 corrosion as appropriate.
(d)
Records.
An operator must maintain records demonstrating
			 compliance with this section. Provided the records show why incorporating
			 design features addressing paragraph (a)(1), (a)(2), or (a)(3) of this section
			 is impracticable or unnecessary, an operator may fulfil! this requirement
			 through written procedures supported by as-built drawings or other construction
			 records.
§ 192.477
Internal Corrosion Control: Monitoring
!f corrosive gas is being transported, coupons or other
				suitable means must be used to determine the effectiveness of the steps taken
				to minimize internal corrosion. Each coupon or other means of monitoring
				internal corrosion must be checked two times each calendar year, but with
				intervals not exceeding 7½ months.
§ 192.479
Atmospheric Corrosion
			 Control: General
(a) Each operator
			 must clean and coat each pipeline or portion of pipeline that is exposed to the
			 atmosphere, except pipelines under paragraph (c) of this section.
(b) Coating material must be suitable for the
			 prevention of atmospheric corrosion.
(c) Except portions of pipelines in offshore
			 splash zones or soil-to-air interfaces, the operator need not protect from
			 atmospheric corrosion any pipeline for which the operator demonstrates by test,
			 investigation, or experience appropriate to the environment of the pipeline
			 that corrosion will-
(1) Only be a light
			 surface oxide; or
(2) Not affect
			 the safe operation of the pipeline before the next scheduled
			 inspection.
§
			 192.481
Atmospheric Corrosion Control: Monitoring
(a) Each operator must inspect each pipeline
			 or portion of pipeline that is exposed to the atmosphere for evidence of
			 atmospheric corrosion, as follows:
If the pipeline is located......
Then the frequency of inspections is:
Onshore
At least once every 3 calendar years, but with
						  intervals not exceeding 39 months.
Offshore
At least once each calendar year, but with intervals
						  not exceeding 15 months.
(b)
			 During inspections the operator must give particular attention to pipe at
			 soil-to-air interfaces, under thermal insulation, under disbonded coatings, at
			 pipe supports, in splash zones, at deck penetrations, and in spans over
			 water.
(c) If atmospheric corrosion
			 is found during an inspection, the operator must provide protection against the
			 corrosion as required by § 192.479.
§ 192.483
Remedial Measures:
			 General
(a) Each segment of metallic
			 pipe that replaces pipe removed from a buried or submerged pipeline because of
			 external corrosion must have a properly prepared surface and must be provided
			 with an external protective coating that meets the requirements of §
			 192.461.
(b) Each segment of
			 metallic pipe that replaces pipe removed from a buried or submerged pipeline
			 because of external corrosion must be cathodically protected in accordance with
			 this subpart.
(c) Except for cast
			 iron or ductile iron pipe, each segment of buried or submerged pipe that is
			 required to be repaired because of external corrosion must be cathodically
			 protected in accordance with this subpart.
§ 192.485
Remedial Measures:
			 Transmission Lines
(a)
General
			 corrosion.
Each segment of transmission line with general corrosion
			 and with a remaining wall thickness less than that required for the MAOP of the
			 pipeline must be replaced or the operating pressure reduced commensurate with
			 the strength of the pipe based on actual remaining wall thickness. However,
			 corroded pipe may be repaired by a method that reliable engineering tests and
			 analyses show can permanently restore the serviceability of the pipe. Corrosion
			 pitting so closely grouped as to affect the overall strength of the pipe is
			 considered general corrosion for the purpose of this paragraph.
(b)
Localized corrosion
			 pitting.
Each segment of transmission line pipe with localized
			 corrosion pitting to a degree where leakage might result must be replaced or
			 repaired, or the operating pressure must be reduced commensurate with the
			 strength of the pipe, based on the actual remaining wall thickness in the
			 pits.
(c) Under paragraphs (a) and
			 (b) of this section, the strength of pipe based on actual remaining wall
			 thickness may be determined by the procedure in ASME/ANSI B31G or the procedure
			 in AGA Pipeline Research Committee Project PR 3-805 (with RSTRENG disk). Both
			 procedures apply to corroded regions that do not penetrate the pipe wall,
			 subject to the limitations prescribed in the procedures.
§ 192.487
Remedial Measures:
			 Distribution Lines Other Than Cast Iron or Ductile Iron Lines
(a)
General corrosion.
Except for cast iron or ductile iron pipe, each segment of generally corroded
			 distribution line pipe with a remaining wall thickness less than that required
			 for the MAOP of the pipeline, or a remaining wall thickness less than 30
			 percent of the nominal wall thickness, must be replaced. However, corroded pipe
			 may be repaired by a method that reliable engineering tests and analyses show
			 can permanently restore the serviceability of the pipe. Corrosion pitting so
			 closely grouped as to affect the overall strength of the pipe is considered
			 general corrosion for the purpose of this paragraph.
(b)
Localized corrosion
			 pitting.
Except for cast iron or ductile iron pipe, each segment of
			 distribution line pipe with localized corrosion pitting to a degree where
			 leakage might result must be replaced or repaired.
§ 192.489
Remedial Measures: Cast
			 Iron and Ductile Iron Pipelines.
(a)
General graphitization.
Each segment of cast iron or ductile
			 iron pipe on which general graphitization is found to a degree where a fracture
			 or any leakage might result, must be replaced.
(b)
Localized
			 graphitization.
Each segment of cast iron or ductile iron pipe on
			 which localized graphitization is found to a degree where any leakage might
			 result, must be replaced or repaired, or sealed by internal sealing methods
			 adequate to prevent or arrest any leakage.
§ 192.490
Direct
			 assessment.
Each operator that uses direct assessment as defined in §
				192.903 on an onshore transmission line made primarily of steel or iron to
				evaluate the effects of a threat in the first column must carry out the direct
				assessment according to the standard listed in the second column. These
				standards do not apply to methods associated with direct assessment, such as
				close interval surveys, voltage gradient surveys, or examination of exposed
				pipelines, when used separately from the direct assessment process.
Threat
Standard1
External corrosion
§ 192.9252
Internal corrosion in pipelines that
transport dry gas
§ 192.927
Stress corrosion cracking
§ 192.929
1 For lines not
			 subject to subpart O of this part, the terms "covered segment" and "covered
			 pipeline segment" in §§ 192.925, 192.927, and 192.929 refer to the
			 pipeline segment on which direct assessment is performed.
2 In § 192.925(b), the provision
			 regarding detection of coating damage applies only to pipelines subject to
			 subpart O of this part.
§
			 192.491
Corrosion Control Records.
(a) Each operator shall maintain records or
			 maps to show the location of cathodically protected piping, cathodic protection
			 facilities, other than unrecorded galvanic anodes installed before August 1,
			 1971, and neighboring structures bonded to the cathodic protection
			 system.
(b) Each of the following
			 records must be retained for as long as the pipeline remains in service:
(1) Each record or map required by paragraph
			 (a) of this section;
(2) Records of
			 each test, survey, or inspection required by this subpart, in sufficient detail
			 to demonstrate the adequacy of corrosion control measures or that a corrosive
			 condition does not exist.