What Are the Requirements for Using Internal Corrosion Direct Assessment (ICDA)? [49 CFR 192.927]

(A)A. Definition. Internal Corrosion Direct Assessment (ICDA) is a process an operator uses to identify areas along the pipeline where fluid or other electrolyte introduced during normal operation or by an upset condition may reside, and then focuses direct examination on the locations in covered segments where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, or fluid with CO2, O2, hydrogen sulfide or other contaminants present in the gas. [49 CFR 192.927(a)]#

(B)B. General Requirements. An operator using direct assessment as an assessment method to address internal corrosion in a covered pipeline segment must follow the requirements in this Section and in NACE SP0206 (incorporated by reference, see §507). The Dry Gas Internal Corrosion Direct Assessment (DG-ICDA) process described in this Section applies only for a segment of pipe transporting nominally dry natural gas (see § 507), and not for a segment with electrolyte nominally present in the gas stream. If an operator uses ICDA to assess a covered segment operating with electrolyte present in the gas stream, the operator must develop a plan that demonstrates how it will conduct ICDA in the segment to address effectively internal corrosion, and must notify PHMSA in accordance with §518. In the event of a conflict between this section and NACE SP0206, the requirements in this section control. [49 CFR 192.927(b).]#

(C)C. The ICDA Plan. An operator must develop and follow an ICDA plan that meets NACE SP0206 (incorporated by reference, see §507) and that implements all four steps of the DG-ICDA process, including pre-assessment, indirect inspection, detailed examination at excavation locations, and post-assessment evaluation and monitoring. The plan must identify the locations of all ICDA regions within covered segments in the transmission system. An ICDA region is a continuous length of pipe (including weld joints), uninterrupted by any significant change in water or flow characteristics, that includes similar physical characteristics or operating history. An ICDA region extends from the location where liquid may first enter the pipeline and encompasses the entire area along the pipeline where internal corrosion may occur until a new input introduces the possibility of water entering the pipeline. In cases where a single covered segment is partially located in two or more ICDA regions, the four-step ICDA process must be completed for each ICDA region in which the covered segment is partially located to complete the assessment of the covered segment. [49 CFR 192.927(c)]#

(1)1. 1.Preassessment. An operator must comply with NACE SP0206 (incorporated by reference, see §507) in conducting the preassessment step of the ICDA process. [49 CFR 192.927(c)(1)]#

(2)2. Indirect Inspection. An operator must comply with NACE SP0206 (incorporated by reference, see §507), and the following additional requirements, in conducting the Indirect Inspection step of the ICDA process. An operator must explicitly document the results of its feasibility assessment as required by NACE SP0206, section 3.3 (incorporated by reference, see §507); if any condition that precludes the successful application of ICDA applies, then ICDA may not be used, and another assessment method must be selected. When performing the indirect inspection, the operator must use actual pipeline-specific data, exclusively. The use of assumed pipeline or operational data is prohibited. When calculating the critical inclination angle of liquid holdup and the inclination profile of the pipeline, the operator must consider the accuracy, reliability, and uncertainty of the data used to make those calculations, including, but not limited to, gas flow velocity (including during upset conditions), pipeline elevation profile survey data (including specific profile at features with inclinations such as road crossings, river crossings, drains, valves, drips, etc.), topographical data, and depth of cover. An operator must select locations for direct examination and establish the extent of pipe exposure needed (i.e., the size of the bell hole), to account for these uncertainties and their cumulative effect on the precise location of predicted liquid dropout. [49 CFR 192.927(c)(2)] .#

(3)3. Detailed Examination. An operator must comply with NACE SP0206 (incorporated by reference, see §507) in conducting the detailed examination step of the ICDA process. When an operator first uses ICDA for a covered segment, an operator must identify a minimum of two locations for excavation within each covered segment associated with the ICDA region and must perform a detailed examination for internal corrosion at each location using ultrasonic thickness measurements, radiography, or other generally accepted measurement techniques that can examine for internal corrosion or other threats that are being assessed. One location must be the low point (e.g., sag, drip, valve, manifold, dead-leg) within the covered segment nearest to the beginning of the ICDA region. The second location must be further downstream, within the covered segment, near the end of the ICDA region. Whenever corrosion is found during ICDA at any location, the operator must: [49 CFR 192.927(c)(3)]#

(a)a. evaluate the severity of the defect (remaining strength) and remediate the defect in accordance with §3333; if the condition is in a covered segment, or in accordance with §§2137 and 2914 if the condition is not in a covered segment; [49 CFR 192.927(c)(3)(i)]#

(b)b. expand the detailed examination program to determine all locations that have internal corrosion within the ICDA region, and accurately characterize the nature, extent, and root cause of the internal corrosion. In cases where the internal corrosion was identified within the ICDA region but outside the covered segment, the expanded detailed examination program must also include at least two detailed examinations within each covered segment associated with the ICDA region, at the location within the covered segment(s) most likely to have internal corrosion. One location must be the low point (e.g., sags, drips, valves, manifolds, dead-legs, traps) within the covered segment nearest to the beginning of the ICDA region. The second location must be further downstream, within the covered segment. In instances of first use of ICDA for a covered segment, where these locations have already been examined in accordance with Paragraph C.3 of this section, two additional detailed examinations must be conducted within the covered segment; and [49 CFR 192.927(c)(3)(ii)]#

(c)c. expand the detailed examination program to evaluate the potential for internal corrosion in all pipeline segments (both covered and non-covered) in the operator's pipeline system with similar characteristics to the ICDA region in which the corrosion was found and remediate identified instances of internal corrosion in accordance with either §3333 or §§2137 and 2914, as appropriate. [49 CFR 192.927(c)(3)(iii)]#

(4)4. Post-Assessment Evaluation and Monitoring. An operator must comply with NACE SP0206 (incorporated by reference, see §507) in performing the post assessment step of the ICDA process. In addition to NACE SP0206, the evaluation and monitoring process must also include: [49 CFR 192.927(c)(4)]#

(a)a. an evaluation of the effectiveness of ICDA as an assessment method for addressing internal corrosion and determining whether a covered segment should be reassessed at more frequent intervals than those specified in §3339. An operator must carry out this evaluation within 1 year of conducting an ICDA; [49 CFR 192.927(c)(4)(i)]#

(b)b. validation of the flow modeling calculations by comparison of actual locations of discovered internal corrosion with locations predicted by the model (if the flow model cannot be validated, then ICDA is not feasible for the segment); and [49 CFR 192.927(c)(4)(ii)]#

(c)c. continuous monitoring of each ICDA region that contains a covered segment where internal corrosion has been identified by using techniques such as coupons or ultrasonic (UT) sensors or electronic probes, and by periodically drawing off liquids at low points and chemically analyzing the liquids for the presence of corrosion products. An operator must base the frequency of the monitoring and liquid analysis on results from all integrity assessments that have been conducted in accordance with the requirements of this subpart and risk factors specific to the ICDA region. At a minimum, the monitoring frequency must be two times each calendar year, but at intervals not exceeding 7 1/2 months. If an operator finds any evidence of corrosion products in the ICDA region, the operator must take prompt action in accordance with one of the two following required actions, and remediate the conditions the operator finds in accordance with §3333 or §§2137 and 2914, as applicable: [49 CFR 192.927(c)(4)(iii)]#

(i)i. conduct excavations of, and detailed examinations at, locations downstream from where the electrolytes might have entered the pipe to investigate and accurately characterize the nature, extent, and root cause of the corrosion; or [49 CFR 192.927(c)(4)(iii)(A)]#

(ii)ii. assess the covered segment using another integrity assessment method allowed by this subpart. [49 CFR 192.927(c)(4)(iii)(B)]#

(5)5. Other Requirements. The ICDA plan must also include the following: [49 CFR 192.927(c)(5)]#

(a)a. criteria an operator will apply in making key decisions (including, but not limited to, ICDA feasibility, definition of ICDA Regions and sub-regions, conditions requiring excavation) in implementing each stage of the ICDA process; [49 CFR 192.927(c)(5)(i)]#

(b)b. provisions that the analysis be carried out on the entire pipeline in which covered segments are present, except that application of the remediation criteria of §3333 may be limited to covered segments. [49 CFR 192.927(c)(5)(ii)]#

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

HISTORICAL NOTE: Promulgated by the Department of Natural Resources, Office of Conservation, Pipeline Division, LR 30:1279 (June 2004), amended LR 31:687 (March 2005), LR 33:484 (March 2007), LR 35:2812 (December 2009), LR 50:1258 (September 2024), amended by the Department of Conservation and Energy, Office of Enforcement, LR 51:1837 (November 2025).#