NACE SP0113-2013

NACE SP0113-2013 Item No. 21171

Standard Practice Pipeline Integrity Method Selection This NACE International standard represents a consensus of those individual members who have reviewed this document, document, its scope, scope, and provisions. provisions. Its acceptance does not in any respect respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE NACE standard is to be construed construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by letters patent, or as indemnifying or protecting anyone against liability for infringement of letters patent. This standard represents minimum minimum requirements and should should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating relating to the subject. Unpredictable circumstances circumstances may negate the usefulness of this standard in specific instances. instances. NACE assumes no responsibility responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE interpretations issued by NACE in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE standard may not necessarily necessarily address all potential health health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred referred to within this this standard. Users of this NACE standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE standards are subject subject to periodic review, and may may be revised or withdrawn at any time in accordance accordance with NACE technical committee committee procedures. NACE requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication publication and subsequently from from the date of each reaffirmation reaffirmation or revision. revision. The user is cautioned to obtain the latest edition. edition. Purchasers of NACE standards standards may receive current information on all standards and other NACE publications by contacting the NACE First Service Service Department, 1440 South Creek Dr., Houston, TX 77084 -4906 (telephone +1 281-228-6200).  Approved 2013-03-16 NACE International 1440 South Creek Drive Houston, Texas 77084-4906 +1 281-228-6200 ISBN 1-57590-259-1 ©2013, NACE International

SP0113-2013

 __________  _______________ __________ __________ __________ ___________ ___________ __________ __________ __________ __________ __________ __________ _______ __ Foreword This standard practice provides guidance on determining the appropriate integrity assessment method for diagnosing the corrosion corrosion threats recognized as part of a pipeline integrity integrity process. This NACE integrity assessment methodology is limited to addressing external corrosion (EC), internal corrosion (IC), and stress corrosion corrosion cracking cracking (SCC). It has the potential potential to indicate indicate prior mechanical damage threats, such as third party or vandalism, and it cannot locate threats that are the result of equipment damage, manufacturing technologies, construction practices, incorrect operations, or weather and external external force. The integrity assessment assessment techniques to be covered covered include in-line inspection (ILI), direct assessment (DA), pressure testing, and other new technology techniques. The pipeline integrity process is a continuous improvement process. A particular assessment integrity method may may not be the same one one used for the first and subsequent assessment. assessment. The lessons learned after each assessment assist in determining the appropriate method for subsequent assessments. assessments. Through successive successive applications applications of the integrity integrity assessment assessment methods, methods, a pipeline operator should be able to identify and address locations at which corrosion activity has occurred, is occurring, occurring, or may occur. The process is intended intended to assist in locating locating areas where defects could form in the future rather than only identifying those areas where defects have already formed. This standard is intended for use by individuals and teams planning, implementing, and managing corrosion integrity assessment projects and programs, including managers, supervisors, and engineers. The integrity assessment process in this standard is specifically intended to address buried onshore pipelines constructed from ferrous materials. Users of this standard must be familiar with all applicable pipeline safety regulations and industry standards for the jurisdiction in which the pipeline operates. This includes all regulations requiring specific pipeline integrity assessment assessment practices and programs. This NACE Standard was developed by Task Group (TG) 401, “Integr ity “Integr ity Assessment Tool Selection,” which is administered by Specific Technology Group (STG) 35, “Pipelines, Tanks, and Well Casings.” This standard is issued issued by NACE International International under the auspices of STG 35.

In NACE standards, the terms shall, must , should, and may   are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shall and must  are  are used to state a requirement, and are considered mandatory. The term should  is   is used to state something good and is recommended, but is not considered mandatory. The term may   is used to state something considered optional.

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NACE International Standard Practice Pipeline Integrity Method Selection Contents 1. General............. .................. ................. ................. .................. ................. .................. .......... 1 2. Definitions ................. ................. .................. ................. ................. .................. .................. . 2 3. Technology Descriptions .................. ................. .................. ................. .................. ............. 3 4. First-Time Assessment ................. ................. .................. ................. .................. .............. 12 5. Subsequent Assessments .................. ................. .................. ................. .................. ........ 15 References .............................................................................................................................. 18 Bibliography ............................................................................................................................. 19 Table 1: Standards and Reports on Assessment Processes ................. .................. ................ 3

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SP0113-2013  _________________________________________________________________________ Section 1: General 1.1 Introduction 1.1.1 Corrosion integrity assessment is a process for improving pipeline safety. Its primary purpose is to prevent future corrosion damage. 1.1.2 For accurate and correct application of this standard, the standard shall be used in its entirety. Using or referring to only specific paragraphs or sections may lead to misinterpretation and misapplication of the recommendations and practices contained herein. 1.1.3 This standard provides the evaluation methodology, but does not designate practices for every specific or unique situation because of the complexity of conditions to which buried piping systems are exposed. 1.1.4 This standard presents a methodology for the selection of integrity assessment methods for external corrosion, internal corrosion, and SCC on onshore ferrous pipelines carrying natural gas and hazardous liquids. 1.1.5 This standard provides flexibility for the pipeline operator to tailor the corrosion integrity assessment method to specific pipeline situations. 1.1.6 This methodology is a continuous improvement process. Through periodic successive assessments, the process should identify and address locations at which corrosion activity has occurred, is occurring, or may occur, and show the effectiveness of various mitigation programs. 1.1.6.1 This methodology provides the advantage and benefit of locating areas in which corrosion wall loss may form in the future rather than only areas in which corrosion defects have already formed. 1.1.6.2 Comparing the results of the successive periodic assessments is one method of evaluating the integrity assessment process, determining the effectiveness, and demonstrating that confidence in the integrity of the pipeline with respect to the corrosion threats continuously improving. 1.1.7 The individual integrity assessment processes may detect pipeline integrity threats other than EC, IC, and SCC, such as mechanical damage, microbiologically influenced corrosion (MIC), etc. When such threats are detected, additional assessments and inspections should be performed. The pipeline operator should utilize appropriate assessment methods (1) (2) 1 2 3 (3) 4 such as those listed in ANSI /ASME  B31.4,  ANSI/ASME B31.8,  ANSI/ASME B31.8S,  and API  1160  to address each of these other risks. 1.1.8 Each integrity assessement method complements the others. They do not have identical performance, but each has advantages over the others. All pipelines may be successfully assessed with just one particular method. Precautions should be taken when applying these methodologies, just as with other assessment methods, in order to choose what is most appropriate. 1.1.9 The provisions of this standard should be applied under the direction of competent persons who, by reason of knowledge of the physical sciences and the principles of engineering and mathematics, acquired by education and related practical experience, are qualified to engage in the practice of corrosion control and risk assessment on buried ferrous piping systems. Such persons may be registered professional engineers or persons recognized as corrosion specialists or cathodic protection (CP) specialists by organizations such as NACE or engineers or technicians with suitable levels of experience, if their professional activities include external corrosion control of buried ferrous piping systems.

(1)

 American National Standards Institute (ANSI), 25 West 43rd St., 4th Floor, New York, NY 10036.  ASME International (ASME), Three Park Ave., New York, NY 10016-5990. (3)  American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005. (2)

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SP0113-2013  _________________________________________________________________________ Section 2: Definitions Dent: A local change in piping surface contour caused by an external force such as mechanical impact or rock impact. Dry Gas Internal Corrosion Direct Assessment: The internal corrosion direct assessment process as defined in this standard applicable to normally dry gas systems. External Corrosion Direct Assessment:  A four-step process that combines pre-assessment, indirect inspection, direct examination, and post assessment to evaluate the effect of external corrosion on the integrity of a pipeline. Examination: A direct physical inspection touching the exposed profile of a pipeline anomaly by a person, which may include the use of nondestructive examination techniques. Gouge: Elongated grooves or cavities usually caused by mechanical removal of metal. Hydrostatic Test: A pressure test of a pipeline in which the pipeline is completely filled with water and pressurized to ensure it meets the design strength conditions and is free of leaks. In-Line Inspection:  An inspection of a pipeline from the interior of the pipe using an in-line inspection tool. (also called intelligent or smart pigging ) In-Line Inspection Tool: The device or vehicle that uses a nondestructive testing technique to inspect the pipeline from the inside. (also known as intelligent or smart pig ) Launcher: A device used to insert an in-line inspection tool into a pressurized pipeline. (also known as  pig trap or scraper trap) Magnetic Flux Leakage: A type of in-line inspection technology in which a magnetic field is induced in the pip e wall between two poles of a magnet. Anomalies affect the distribution of the magnetic flux in the wall. The magnetic flux leakage pattern is used to detect and characterize anomalies. Metal Loss: Any pipe anomaly in which metal has been removed. Metal l oss is usually the result of corrosion, but gouging, manufacturing defects, or mechanical damaging can also cause wall thinning. Nondestructive Examination: The evaluation of results from x-ray, ultrasonic, or other testing methods or techniques that detect, locate, measure, and evaluate anomalies without sectioning the pipe (see nondestructive testing ). Nondestructive Testing:  A process that involves the inspection, testing, or evaluation of materials, components, and assemblies for materials’ discontinuities, properties, and machine problems without further impairing or destroying the part’s serviceability. Nondestructive Testing Method:  A particular method of nondestructive testing, such as radiography, ultrasonic, magnetic testing, liquid penetrant, visual, leak testing, eddy current, and acoustic emission. Nondestructive Testing Technique: A specific way of utilizing a particular nondestructive testing method that distinguishes it from other ways of applying the same nondestructive testing method. For example, magnetic testing is a nondestructive testing method, while magnetic flux leakage and magnetic particle inspection are nondestructive testing techniques. Similarly, ultrasonic is a nondestructive testing method, while contact shear-wave ultrasonic, and contact compression-wave ultrasonic are nondestructive testing techniques. Operator: A person or organization that owns or operates pipeline facilities as an owner or as an agent for an owner. Piggability: A characteristic of a pipeline or pipeline section that has no restrictions for running in-line inspection tools (pigs). Pipeline: A continuous part of a pipe system used to transport a hazardous liquid or gas. A pipeline includes pipe, valves, fittings, and other appurtenances attached to the p ipe.

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SP0113-2013 Pipeline System:  All portions of the physical facilities through which gas, oil, or product moves dur ing transportation. This includes pipe, valves, fittings, and other appurtenances attached to the pipe, compressor units, pumping units, metering stations, regulator stations, delivery stations, tanks, holders, and o ther fabricated assemblies. Pressure: Level of force per unit area exerted on the inside of a pipe or vessel. Pressure Testing: A method of leak testing in which the component being tested is filled completely with a gas or liquid which is then pressurized. The outside of the component is examined for the detection of any leaks. Receiver: A pipeline facility used for removing a pig from a pressurized pipeline. It may be referred to as trap, pig trap, or scraper trap. Root-Cause Analysis (from ASME B31.8S): Family of processes implemented to determine the primary cause of an event. These processes all seek to examine a cause-and-effect relationship through the organization and analysis of data. Rupture: The instantaneous tearing or fracturing of pipe material causing large-scale product or water loss. Seam Weld: The longitudinal or spiral weld in pipe, which is made in the pipe mill. Smart Pig: See In-Line Inspection Tool. Spike Test:  A hydrostatic test which consists of a short duration test at a high “peak” pressure to test the structural integrity of the pipeline. The pressure is then reduced for a longer-term pressure test designed to detect leaks. Ultrasonic Testing: A type of inspection technology that uses ultrasound for volumetric inspection of the pipe.

 _________________________________________________________________________ Section 3: Technology Descriptions 3.1 The purpose of this section is to give a high-level overview of available assessment tools and processes. The assessment tools and processes to be described are internal corrosion direct assessment (ICDA), stress corrosion cracking direct assessment (SCCDA), external corrosion direct assessment (ECDA), external corrosion confirmatory direct assessment (ECCDA), ILI, and pressure testing. Specific details regarding these tools and processes may be found in NACE standards and technical committee reports (see Table 1):

Table 1 (A) Standards and Reports on Assessment Processes Integrity Assessment ECDA ICDA

ILI

Pressure Testing

SCCDA (A)

Reference NACE SP0502 (methodology) 6 NACE SP0210  (ECCDA) NACE SP0206 (dry gas) 8 NACE SP0110  (wet gas) 9 NACE SP0208  (liquid petroleum) NACE SP0102 11  API 1163 12 NACE Publication 35100  (nondestructive inspection of pipelines) ASME B31.8  ASME B31.4 13  ANSI/API RP 1110 NACE SP0204

These NACE standards are cited in ASME B31.8S and/or API 1160.

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SP0113-2013 3.2 Dry Gas Internal Corrosion Direct Assessment (Refer to NACE SP0206) 3.2.1 Dry gas internal corrosion direct assessment (DG-ICDA) was developed for natural gas pipelines that normally carry dry gas. These pipelines may suffer from infrequent short-term upsets of entrained electrolyte. Because of this, DG-ICDA is not applicable to wet gathering and producing pipelines (refer to NACE SP0110). 3.2.2 The basis of DG-ICDA for gas pipelines is a detailed examination of locations along the pipeline where water or other entrained electrolyte can accumulate. DG-ICDA allows inferences to be made about the integrity of the remaining downstream length of pipeline. The use of ILI may negate the need to use DG-ICDA. 3.2.3 If the two locations along a length of pipeline farthest downstream from the water introduction point that are most likely to accumulate water have not corroded, other downstream locations are less likely to accumulate water and are unlikely to have suffered corrosion when operating under the same conditions. 3.2.4 DG-ICDA consists of the following four steps: 3.2.4.1 Pre-Assessment. The  pre-assessment step collects essential historic and present operating data about the pipeline, determines whether DG-ICDA is feasible, and then defines ICDA regions. The types of data to be collected are typically available in design and construction records, operating and maintenance histories, alignment sheets, corrosion survey records, gas and liquid analysis reports, and inspection reports from prior integrity evaluations or maintenance actions. 3.2.4.2 Indirect Inspection. The indirect inspection step requires multiphase flow predictions, development of a pipeline elevation profile, and identification of sites where internal corrosion may be present. 3.2.4.3 Detailed Examination The detailed examination step includes performing excavations and conducting detailed examinations of the pipeline to determine whether metal loss from internal corrosion has occurred. Examination of the internal surface of a pipe may use nondestructive examination (NDE) methods that are sufficient to identify and characterize internal defects or wall losses. Inspection data are used to update the indirect examination results to help reprioritize assessment sites. 3.2.4.4 Post Assessment. Post assessment  covers analysis of data collected from the previous three steps to assess the effectiveness of the DG-ICDA process, enact continuous improvement, and determine reassessment intervals. 3.3 Wet Gas Internal Corrosion Direct Assessment (Refer to NACE SP0110) 3.3.1 Wet gas internal corrosion direct assessment (WG-ICDA) methodology assesses where along a pipeline segment internal corrosion severity is potentially highest. The methodology includes existing methods of examination of IC. It can determine the existence of IC, as well as its duration, extent, and severity. 3.3.2 WG-ICDA uses flow modeling results (i.e., dew point, flow velocities, liquid hold-up, and flow patterns) to provide a framework for utilization of those methods. 3.3.3 WG-ICDA is used for onshore and offshore natural gas pipelines that have produced or condensed water as a normal impurity. WG-ICDA is applicable to wet gathering and producing pipelines. WG-ICDA requires the integration of data from the pipeline’s physical characteristics, current and historical operating conditions, multiple field examinations, and inspections to determine and estimate the remaining thickness of the pipeline wall. 3.3.4 WG-ICDA is used for wet gas pipelines and consists of a detailed examination of selected locations with the highest corrosion severity where there may be a reduction of the pipe wall thickness to a level that would pose a threat to the pipeline if mitigation or other measures are not taken before the next assessment. Results at the selected locations can be used to make inferences about the remaining unexamined lengths of the pipeline. 3.3.5

WG-ICDA includes the following four steps:

3.3.5.1 Pre-Assessment. The  pre-assessment step collects all existing, relevant, essential, historic, and current operating data about the pipeline segments, and/or regions and sub-regions relevant to internal corrosion. This includes determining whether WG-ICDA is feasible and defining regions and sub-regions. This step includes determination of regions along a pipeline based on input and withdrawal, determination of sub-regions (within a region) based on pipeline direction/elevation changes. The types of data collected are typically available in design and construction records (e.g., topography, routes, material, design pressures, temperatures, and microstructures),

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SP0113-2013 operating and maintenance histories, flow rates, alignment sheets, corrosion survey records, gas and liquid analysis reports, and inspection reports from prior integrity evaluations and/or maintenance actions, such as cleaning, ILI, or corrosion mitigation. 3.3.5.2 Indirect Inspection. The indirect inspection step covers techniques used for prediction and prioritization of overall corrosion severity at different locations along a pipeline segment to undergo direct assessment (assessment sites). This step reevaluates or improves the definition of the sub-regions as a function of the flow regimes within a sub-region through multiphase flow modeling, determination of corrosion rates within a sub-region, and determination of assessment site sub-regions based on corrosion severity and flow influencing factors within these sub-regions. Calculations are performed using flow models to determine flow regimes and liquid hold-ups; corrosion rate models are used to theoretically estimate corrosion rates; and both models are used to prioritize locations along a pipeline region for susceptibility to internal corrosion. WG-ICDA indirect inspection results in an assessment process that identifies individual factors controlling flow dynamics, corrosion severity, and other factors influenced by corrosion damage. 3.3.5.2.1 WG-ICDA indirect examination is used to identify separate factors controlled by flow dynamics, factors influencing corrosion severity, factors affecting or controlling mitigation, upsets, and other corrosion damageinfluencing factors; and thus performing a smoother assessment process. 3.3.5.2.2 This standard covers internal corrosion related to the transportation of natural gas containing combinations of carbon dioxide (CO 2), hydrogen sulfide (H 2S), oxygen (O2), and other corrosive species. This natural gas can also contain (1) liquid water with corrosive species that are typically found in produced or condensed waters associated with natural gas production, storage, and transportation; (2) microorganisms that may influence corrosion; (3) solids such as deposits, iron sulfide as black powder or scale; and (4) hydrocarbon liquids. 3.3.5.3 Detailed Examination. The detailed examination step includes performing all actions to allow for excavations and conducting direct inspection of assessment sites prioritized by the highest amount of corrosion damage. The examination must have sufficient detail to determine the existence, extent, and severity of corrosion. 3.3.5.3.1 Examination of the internal surface of a pipe may involve NDE methods sufficient to identify and characterize internal defects or wall losses. Incorporation of inspection data to update the indirect examination results is used to help reprioritize assessment sites. 3.3.5.4 Post Assessment. The post-assessment step is an analysis of da ta collected from the previous three steps to assess the effectiveness of the WG-ICDA process; activate and prioritize mitigation, control, and maintenance strategies; enact continuous improvement; and determine future assessment intervals. 3.4 Liquid Petroleum Internal Corrosion Direct Assessment (Refer to NACE SP0208) 3.4.1 Liquid petroleum internal corrosion direct assessment (LP-ICDA) is used for identification and detailed examination of locations along a pipeline in which water or solids can accumulate for extended periods. LP-ICDA results allow for informed conclusions to be made about the integrity of the nonexamined pipeline. If the locations determined to have the highest susceptibility for long-term internally corrosive conditions are examined and found to be free of significant corrosion, other less susceptible locations may be considered to be free of corrosion. LP-ICDA is not applicable to pipelines in which corrosion or leaks have occurred at unpredictable locations. It may not present an economical alternative to in-line inspection for pipelines found to have moderate or higher rates of internal corrosion. 3.4.2 LP-ICDA includes the following four steps: 3.4.2.1 Pre-Assessment.  The pre-assessment step collects essential historic and present operating data about the pipeline, determines whether LP-ICDA is feasible, and then defines LP-ICDA regions. The types of data collected are typically available in design and construction records, operating and maintenance histories, alignment sheets, corrosion survey records, liquid analysis reports, and inspection reports from prior integrity evaluations or maintenance actions. 3.4.2.2 Indirect Inspection.  The indirect inspection step consists of making flow predictions, developing a pipeline elevation profile, and identifying sites along a pipeline segment most likely to have corrosion damage (caused by water, solids accumulation, or both), and other factors affecting corrosion distribution within a LP-ICDA region (e.g., nonsteady flow, temperature profile, or historical pigging operations).

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SP0113-2013 3.4.2.3 Detailed Examination.  The detailed examination step  includes performing excavations and conducting detailed examinations of the pipe to determine whether metal loss from internal corrosion has occurred. 3.4.2.4 Post Assessment.  The post-assessment step  is an analysis of the data collected from the three previous steps. Post assessment determines the effectiveness of the LP-ICDA process, develops conclusions about the integrity of nonexamined pipe, enacts continuous improvement, and determines future assessment intervals. 3.5 External Corrosion Direct Assessment (Refer to NACE SP0502) 3.5.1 ECDA is a continuous improvement process. Through successive applications, ECDA should identify and address locations at which corrosion activity has occurred, is occurring, or may occur. 3.5.2 ECDA provides the advantage and benefit of locating areas where defects may form in the future rather than only areas where defects have already formed. 3.5.3 Comparing the results of successive ECDA applications is one method of evaluating ECDA effectiveness and demonstrating that confidence in the integrity of the pipeline is continuously improving. 3.5.4 ECDA was developed as a process for improving pipeline safety. Its primary purpose is to reduce the threat for future external corrosion damage. 3.5.5 This standard assumes external corrosion is a threat to be evaluated. It may be used to establish a baseline from which future corrosion may be assessed for pipelines on which external corrosion is not currently a significant threat. 3.5.6 ECDA as described in this standard is specifically intended to address buried onshore pipelines constructed from ferrous materials. 3.5.7 This standard should be applied to poorly coated or bare pipelines in accordance with the methods and procedures included herein. Poorly coated pipelines are usually treated as essentially bare if the cathodic current requirements to achieve protection are substantially the same as those for bare pipe. 3.5.8 ECDA requires the integration of data from multiple field examinations and from pipeline surface evaluations with the pipeline’s physical characteristics and operating history. 3.5.9 ECDA includes the following four steps: 3.5.9.1 Pre-Assessment. The pre-assessment step collects historic and current data to determine whether ECDA is feasible, defines ECDA regions, and selects indirect inspection tools. The types of data to be collected are typically available in construction records, operating and maintenance histories, alignment sheets, corrosion survey records, other aboveground inspection records, and inspection reports from prior integrity evaluations or maintenance actions. 3.5.9.2 Indirect Inspection. The indirect inspection step covers aboveground inspections and/or inspections from the ground surface to identify and define the severity of coating faults, other anomalies, and areas where corrosion activity may have occurred or may be occurring. Two or more indirect inspection tools are used over the entire pipeline segment to provide improved detection reliability under the wide variety of conditions that may be encountered along a pipeline right-of-way. 3.5.9.3 Direct Examination.  The direct examination step includes analyses of indirect inspection data to select sites for excavations and pipe surface evaluations. The data from the direct examinations are combined with prior data to identify and assess the impact of external corrosion on the pipeline. In addition, evaluation of pipeline coating performance, corrosion defect repairs, and mitigation of corrosion protection faults are included in this step. 3.5.9.4 Post Assessment.  The  post-assessment step covers analyses of data collected from the previous three steps to assess the effectiveness of the ECDA process, enact continuous improvement, and determine reassessment intervals. 3.6 Stress Corrosion Cracking Direct Assessment (Refer to NACE SP0204) 3.6.1 SCCDA requires the integration of data from historical records, indirect surveys, field examinations, and pipe surface evaluations (i.e., direct examination) combined with the physical characteristics and operating history of the pipeline.

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SP0113-2013 3.6.2 SCCDA provides the advantage and benefit of indicating areas where SCC might occur in the future rather than only areas where SCC is known to exist. 3.6.3 Comparing the results of successive SCCDA applications is one method of evaluating SCCDA effectiveness and demonstrating that confidence in the integrity of the pipeline is continuously improving. 3.6.4 NACE SP0204 assumes SCC is a threat to be evaluated. It may be used to establish a baseline from which future SCC may be assessed for pipelines on which SCC is not currently a significant threat. 3.6.5 SCCDA may be used to prioritize a pipeline system for ILI or hydrostatic testing if significant and extensive SCC is found. 3.6.6 Initial selection of pipeline segments for assessment of risk of high-pH SCC on gas pipelines should be based on Part A3 of ASME B31.8S, Section A3.3. Part A3 considers the following factors: operating stress, operating temperature, distance from compressor station, age of pipeline, and coating type. It is recognized that these screening factors identify a substantial percentage of the susceptible locations, but not necessarily all of them: 3.6.7 A pipeline segment is considered susceptible to high-pH SCC if all of the following factors are met:

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3.6.7.1 The operating stress exceeds 60% of specified minimum yield strength (SMYS). 3.6.7.2 The operating temperature exceeds 38 ºC (100 ºF). 3.6.7.3 The segment is less than 32 km (20 mi) downstream from a compressor station. 3.6.7.4 The age of the pipeline is greater than 10 years. 3.6.7.5 The coating type is other than fusion-bonded epoxy or liquid epoxy (when abrasive surface preparation was used during field application). 3.6.8 A pipeline segment is considered susceptible to near-neutral pH SCC if all of the following factors are met:

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3.6.8.1 The operating stress exceeds 60% of SMYS. 3.6.8.2 The segment is less than 32 km (20 mi) downstream from a compressor station. 3.6.8.3 The age of the pipeline is greater than 10 years. 3.6.8.4 The coating type is other than fusion-bonded epoxy or liquid epoxy (when abrasive surface preparation was used during field application). 3.6.9 SCCDA includes the following four steps: 3.6.9.1 Pre-Assessment.  In the  pre-assessment step, historic and currently available data are collected and analyzed to prioritize the segments within a pipeline system with respect to potential susceptibility to SCC and to select specific sites within those segments for direct examinations. The types of data to be collected are typically available from in-house construction records, operating and maintenance histories, alignment sheets, corrosion survey records, other aboveground inspection records, government sources, and inspection reports from prior integrity evaluations or maintenance actions. 3.6.9.2 Indirect Inspection. In the indirect inspection step, additional data are collected, as deemed necessary by the pipeline operator, to aid prioritization of segments and in site selection. The necessity to conduct indirect inspections and the nature of these inspections depends on the nature and extent of the data obtained in the preassessment step and the data needs for site selection. Typical data collected in this step might include close-interval survey data, direct-current voltage gradient data, and information on terrain conditions (soil type, topography, and drainage) along the right of way. 3.6.9.3 Direct Examination. The direct examination step includes procedures (1) to field verify the sites selected in the first two steps, and (2) to conduct the field digs. Aboveground measurements and inspections are performed to field verify the factors used to select the dig sites. For example, the presence and severity of coating faults might be confirmed. If predictive models based on terrain conditions are used, the topography, drainage, and soil type require

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SP0113-2013 verification. The digs are then performed; the severity, extent, and type of SCC —if any is detected—at the individual dig sites are assessed; and data that may be used in post assessment and predictive-model development are collected. 3.6.9.4 Post Assessment. In the post-assessment step, data collected from the previous three steps are analyzed to determine whether SCC mitigation is required, and if so, to prioritize those actions; to define the interval to the next full integrity reassessment; enact continuous improvement; and to evaluate the effectiveness of the SCCDA approach. 3.7 External Corrosion Confirmatory Direct Assessment (Refer to NACE SP0210) 3.7.1 ECCDA is a continuous improvement process. ECCDA should confirm conclusions drawn from previous assessments and identify and address locations at which corrosion activity is or may b e occurring. 3.7.2 ECCDA provides the advantage and benefit of locating areas where defects may form in the future rather than only areas where defects have already formed. 3.7.3 Comparing the results of successive ECCDA applications is one method of evaluating the effectiveness of the ECCDA process, as well as the ECDA process, and demonstrating that confidence in the integrity of the pipeline is continuously improving. 3.7.4

ECCDA includes the following four steps:

3.7.4.1 Pre-Assessment. The pre-assessment step collects historic and current data to determine whether ECCDA is feasible, defines ECCDA regions, and selects indirect inspection tools. The types of data to be collected are typically available in construction records, operating and maintenance histories, alignment sheets, corrosion survey records, other aboveground inspection records, and inspection reports from prior integrity evaluations, assessments, or maintenance actions. Existing operating conditions should be verified during the  pre-assessment step. 3.7.4.2 Indirect Inspection.  The indirect inspection step requires two or more complementary aboveground inspections. These are used to identify deficiencies in the CP system and locate possible corrosion. A dig prioritization matrix based on a combination of the amplitudes of each inspection technique is required. A combination of these different inspection amplitudes in the matrix are used to prioritize indications for the direct examination digs. A minimum of one indirect inspection tool is required to be used over the entire pipeline segment being assessed. The same complementary tool(s) does not have to be used over the entire pipeline segment.  Additional tools must be used to interpret indications noted with the first tool as defined in the dig prioritization matrix. 3.7.4.3 Direct Examination. The direct examination step includes excavating those site prioritized by the indirect inspection data in the matrix for pipe surface evaluations. The indications noted in the indirect inspection performed for ECCDA should be compared to the anomalies found in previous assessments. New significant indications that have moved up in the prioritization ranking are prime candidates for additional direct examinations. The data from the direct examinations should be combined with prior data to identify and assess the impact of external corrosion on the pipeline, and confirm the dig prioritization matrix. In addition, evaluation of pipeline coating performance, corrosion defect repairs, and mitigation of corrosion control deficiencies are included in this step. 3.7.4.4 Post Assessment.  The  post-assessment step covers analyses of data collected from the previous three steps to assess the effectiveness of the ECCDA process, enact continuous improvement, and confirm reassessment intervals. 3.8 In-Line Inspection (Refer to NACE SP0102) 3.8.1 ILI is an integrity assessment method used to locate and characterize indications in a pipeline. The effectiveness of these flow-driven ILI tools depends on the condition of the specific pipeline section to be inspected and how well the tool matches the requirements set by the inspection objectives. See Table 1 in NACE SP0102 for details pertaining to the effectiveness and limitations of each individual tool. 3.8.1.2

Robotic Tools

The use of robotic tools is an integrity assessment method used to locate and characterize indications in pipelines that were not designed with passage of ILI tools in mind. Robotic tools are useful when ILI is difficult and/or unfeasible for pipelines with short radius, miter bends, gate valves, plug valves, unbarred tees, and without launcher and receiver for

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SP0113-2013 ILI tools. Robotic tools are also useful for pipelines that do not have enough flow to drive ILI tools. The robotic tools are self-propelled at a controlled speed and can carry any one of the tools listed in the following paragraphs through pipelines that cannot be assessed by ILI tools. 3.8.1.3 The minimum requirements for ILI integrity assessments are defined in API 1163. API 1163 sets the standards (4) 15 for tool performance, requires NACE SP0102 to define the operational expectations, and requires ASNT  ILI –PQ  for the qualification of the technologists that interpret the sensor responses. 3.8.2 Metal-Loss Detection Tools 3.8.2.1 There are two principal methods for detection of metal loss in pipe walls: the magnetic flux leakage (MFL) method and the ultrasonic testing (UT) method. MFL was the first method developed and has been the most widely used. A third method, remote field eddy current, has long been used with MFL, but is used only to detect defects on the inside of the pipe wall. Each method has its own particular strengths and limitations. UT tools do not yet reliably couple signals across gas but are effective in liquid product pipelines. 3.8.2.2 Magnetic Flux Leakage Tools 3.8.2.2.1 The basic principles of magnetic flux leakage are straightforward. MFL tools induce an axially oriented magnetic flux into the pipe wall between two poles of a magnet. A homogeneous steel wall without defects creates an undisturbed and uniform distribution of magnetic flux. Metal loss or gain associated with the steel wall causes a change in the distribution of the flux which, in a magneti cally saturated pipe wall, “leaks” out of the pipe wall. Sensors detect and measure this leakage field and hence detect the metal loss. The magnitude and shape of the measured leakage field are used to characterize the size and shape of the region of metal loss. The leakage signals are passed through sophisticated microprocessors, and the resulting data are stored for detailed computer analysis and subsequent reporting. 3.8.2.2.2 MFL ILI tools are commonly classified into categories of standard-resolution (also called low or conventional resolution) and high-resolution (HR). The differences between these categories are the number, size, and orientation of MFL sensors, magnetic circuit design and magnetization levels, and the type of analysis that is applied to recorded data supplied by each type of instrument. Both types of tools use magnets to induce a magnetic field into the pipe wall, and either inductive search coils or solid-state (Hall-effect) sensors to detect flux leakage. Standard-resolution tools have fewer MFL sensors (inductive coil sensors) for a given pipe size than do high-resolution tools. Each of these sensors covers a larger part of the circumference of the pipe and gives an average of the flux leakage distribution in the area that it covers. The much smaller and more advanced Hall sensors (used on HR tools) examine a smaller area of the pipe wall and reveal more detailed information. Therefore, HR tools provide a much better characterization of anomalies in the pipeline. Accordingly, the amount of data is greater and the data processing procedures more sophisticated. 3.8.2.3 Ultrasonic Testing Tools 3.8.2.3.1 UT inspection tools directly measure the pipe wall thickness as the ILI tool travels through the pipeline. They are equipped with transducers that emit ultrasonic signals perpendicular to the surface of the pipe. An echo is received from both the internal and external surfaces of the pipe, and by timing these return signals and comparing them to the speed of ultrasound in pipe steel, the wall thickness is determined. Transducers are deployed in a carrier to cover the circumference of the pipe wall uniformly. 3.8.2.3.2 For efficient transmission of sound from the ultrasonic transducer to the pipe wall and back, ultrasonic inspection procedures typically employ a liquid to “couple” the sound into and back out of the pipe wall. Many liquids usually transported through pipelines provide sufficiently good coupling for UT. In gases, however, because of a mismatch in acoustic properties of steel and gas that lead to difficulties in delivering enough acoustic energy into the pipe wall, ultrasonic inspections are not possible without an additional couplant. Gas pipeline inspections may be performed by utilizing the UT tool in a slug of liquid (e.g., water, diesel oil, etc.) between batching pigs. Electromagnetic acoustic transducer tools (EMAT) use magnetic fields and eddy current to generate ultrasound in pipe wall without a couplant and may be used in gas pipelines.

(4)

American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Ln., Columbus, OH 43228-0518.

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SP0113-2013 3.8.3

Crack Detection Tools

3.8.3.1 Crack detection has become an increasingly important issue in the pipeline industry because of occurrences of crack-like defects (e.g., SCC, fatigue cracks, longitudinal seam weld imperfections, etc.) that are related to leaks and ruptures on operating pipelines. Generally, the NDE technique that allows for the most reliable in-line detection of crack-like defects is UT. Because most crack-like defects (fatigue cracks as well as SCC) are perpendicular to the main stress component (i.e., the hoop stress in a pipe), the ultrasonic pulses are injected at an angle to skip in a circumferential direction to obtain maximum acoustic response as shear waves reflected back from the flat surface. 3.8.3.2

Liquid-Coupled Tools

Liquid-coupled tools utilize shear waves generated in the pipe wall by angular transmission of the ultrasonic pulses through a liquid coupling medium (e.g., oil, water, etc.). The angle of incidence is adjusted such that effective propagation is obtained in pipeline steel. This technique is appropriate for crack inspection, and it is established as one of the standard techniques in UT. 3.8.3.3

Electromagnetic Acoustic Transducer Tools

EMAT consists of a coil inside a magnetic field held off the internal surface of the pipe wall. Alternating current (AC) placed through the coil induces a current in the pipe wall, causing Lorentz forces (force acting on moving charges in magnetic fields), which in turn generate a directional ultrasound signal. The type and the configuration of the transducer used define the types and modes of generated ultrasound and the characteristics of its propagation through the pipe wall. EMATs do not require a coupling medium and thus are readily applicable in gas pipelines. 3.8.3.4

Remote Field Eddy Current Tools

Remote field eddy current (RFEC) tools consist of an exciter coil placed in the middle of the pipe and concentric to the pipe axis. The exciter coil is energized with a low-frequency AC current to produce a corresponding magnetic field. This magnetic field passes out of the pipe wall near the exciter coil, travels along the outside of the pipe, and reenters the pipe at the location of the detector coils placed at the internal surface of the pipe wall.  Any detectable features present in the pipe wall change the behavior of the magnetic field. RFEC does not require a coupling medium and is readily applicable in gas pipelines. Robotic ILI tools may carry a RFEC tool for inspection of nonpiggable pipelines. Their performance characteristics include a capability of detecting metal loss, indirectly measuring the wall thickness, and discriminating between internal and external defects. 3.8.3.5 Other Methods Other methods that have been developed for crack detection in pipelines include circumferential MFL tools. These tools magnetize the pipe wall circumferentially. Most cracks are very tight and therefore do not alter the propagation of magnetic flux sufficiently to enable reliable detection. On the other hand, stress concentration associated with cracks changes the magnetic properties of pipe steel and thus changes the propagation of magnetic flux, which, in turn, causes increased probability of detection. 3.9 Pressure Testing 3.9.1 Pressure testing using air or water is an industry-accepted method for validating the integrity of gas- and liquidcontaining pipelines. The idea of the pressure test is to show that the pipeline is free of injurious defects that would cause a leak or a rupture in service. If such defects are present, they will fail during the test, releasing the test medium instead of the product that would be released in the event of a service failure. Injurious defects may or may not exist in a pipeline, but if they do, a pressure test will cause them to fail, one-by-one in order of decreasing severity as the pressure is raised higher and higher. The target test pressure is intentionally set at a level sufficiently above the maximum operating pressure to assure a margin of safety. 3.9.1.1 Defects that are too small to fail at the target test pressure remain after the test, but their failure pressure is well above the maximum operating pressure. A pressure test either eliminates defects that would fail in service, or it proves that none existed. To the extent that the test pressure exceeds the maximum operating pressure, the test demonstrates a margin of safety by eliminating or proving the absence of defects with failure pressures between the  16 maximum operating pressure and the test pressure.

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SP0113-2013 3.9.1.2 This method may include a spike, strength test, and/or a leak test. API 1110, ASME B31.8 (Appendix N), and  ASME B31.4 contain details on conducting pressure tests for both post-construction and subsequent testing after a pipeline has been in service for a period of time. The code specifies the test pressure that should be attained and the test duration to address certain threats. It also specifies allowable test media and under which conditions the various test media may be used. The spike test procedure is described in API 1110. 3.9.2 When pressure testing is performed, considerations include: Precleaning of the pipeline using pigs to remove corrosion and scale or those other deposits that may contain bacteria; 

Post cleaning of the pipeline using cleaning pigs to remove the test medium and prevent internal corrosion from occurring; 

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Avoid entrapment of excessive air during filling;

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Plan contingencies in the event of a failure;

Attainment of permits and coordination of activities with local agencies (including water access, cleaning, and disposal issues); and 

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Providing an alternate source of product to those affected by the pressure testing (e.g., customers).

3.9.3 Test Medium  Although different types of gases and liquids can be used for testing, water testing is superior to gas testing under otherwise identical conditions because of problems in detecting leaks with gas. The sensitivity of leak detection based on pressure drop for water testing is excellent for test sections on the order of tens of miles. Because of concerns for running fractures associated with higher pressure gas testing, such testing should be avoided in pipelines that are not built of 17 closely controlled high-toughness steels, particularly if methane is to be used as the test gas. 3.10

Other Tools and Technologies 3.10.1 Guided Wave Testing Guided wave testing (GWT) allows the rapid screening of one to four joint lengths of pipe in locations that are difficult to access. This UT technology screens the pipe volume for reflectors that could be wall loss or cracks. Reflectors of sufficient magnitude trigger the need to conduct a second inspection (such as ILI) or excavate suspect areas for closer examination by local NDT techniques. This ability to inspect locations that are difficult to access is a significant factor in favor of applying guided waves. This method also utilizes the ability to examine road or rail crossings by testing from the nearest accessible location (or from both sides of the crossing), thereby increasing the proportion of any pipe system that can be inspected. Research has shown GWT is able to find defects that would pass a pressure test. 3.10.1.1 GWT includes the following four steps: 3.10.1.1.1 Pre-Assessment.  The  pre-assessment step  evaluates whether the use of GWT technology has the potential to meet the objectives of the assessment project and to collect the data necessary to facilitate the inspection process. Specific information relating to the line geometry, flaw types and sizes to be detected, coating type and thickness (if applicable), desired length of pipe to be inspected, and test location possibilities should be determined.  An appropriate GWT system should then be selected accordingly. 3.10.1.1.2 Indirect Inspection.  The indirect inspection step  involves the inspection of the pipe using the GWT equipment to identify and prioritize suspect areas for prove-up using conventional direct examination technologies. The inspection distance is a function of the sound-dampening characteristics of the system. Pipe containing multiple fittings (such as elbows and/or multiple wall thickness changes) and pipe covered with thick coal tar and similar coatings may have a reduced inspection length. The GWT technique cannot distinguish between exterior and interior reflections. 3.10.1.1.3 Direct Examination.  The direct examination step  is conducted after the GWT inspection has been completed and involves an examination of the pipe surface (if exterior) or X-ray examination (if interior) to investigate any indications that have been identified.

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SP0113-2013 3.10.1.1.4 Post Assessment. The objectives of the  post-assessment step are to provide interpretation and translation of inspection and field data, recommend further investigations or remedial actions, validate the quality and results of the data collected, enact continuous improvement, and define reassessment intervals. 3.10.2 New and Emerging Technologies 3.10.2.1 The operator should continuously monitor the new technology literature that becomes available. (5) (6) (7) (8) Organizations such as GTI,  DOE,  PRCI,  and NYSEARCH  may have information on n ew technologies. 3.10.2.2 An operator must be cautious when utilizing a new technology to ensure that it has demonstrated its ability to perform an adequate assessment and provide an equivalent understanding of the pipeline that is comparable to ILI, DA, or pressure testing.

 _________________________________________________________________________ Section 4: First-Time Assessment 4.1 Introduction The decision as to what technology to utilize for the first-time assessment of a segment of pipeline must take a number of riskrelated factors into consideration. Section 4 covers: 

Operating pressure as % SMYS;

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Length and diameter of the segment;

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Pipeline accessibility or piggability;

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Inspection difficulties such as shielding coatings;

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The expectation of excessive corrosion;

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Right of way, accessibility, and number of digs;

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Significant interference threats to CP system;

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Presence of historical mill and construction problems, such as a long-seam threat;

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Other threats that interact with and are known to accelerate corrosion;

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Operational economics and reliability of service;

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Operational considerations; and

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Environmental considerations.

4.2 The methodology and technology selected must be the one best suited to address the corrosion threats to a given pipeline section. The decision regarding ILI, DA, pressure testing, or the use of other technology should acknowledge the benefits and limitations of each in terms of pipeline safety and reliability as well as the benefits to maintenance. 4.3 Percent Specified Minimum Yield Strength  An operator may establish a rupture pressure lower boundary threshold. Above this threshold, ILI should be considered the strongly preferred inspection method. The intent of this rupture pressure threshold is to identify lines that are more likely to fail by (5)

Gas Technology Institute (GTI), 1700 South Mount Prospect Rd., Des Plaines, IL 60018. U.S. Department of Energy (DOE), 1000 Independence Ave. SW, Washington, DC 20585. (7) Pipeline Research Council International (PRCI), 1401 Wilson Blvd., Suite 1101, Arlington, VA 22209. (8) The NYSEARCH Committee is a voluntary suborganization within the Northeast Gas Association, 75 Second Avenue, Ste. 510, Needham, MA 02494-2859. (6)

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SP0113-2013 rupturing than by leaking. As the likelihood of failure by rupture increases, the total risk of failure is increased. For instance, the potential impact radius associated with the rupture pressure of a pipeline operating at 30% SMYS is significantly larger than the same pipeline operating at a lower percentage of SMYS. Thus, as the percentage of SMYS pressure is increased, both the probability of failure by rupture and the consequences of failure increase. 4.4 Length and Diameter of the Segment 4.4.1 ILI is considered the preferred technology. An economic choice may be established by the operator for the section of pipeline required for ILI. The ILI cost is established using two major factors. First, the probability of having an integrity issue is greater when the length of pipeline that exposes the public or environmentally sensitive areas to the risk of a pipeline failure is longer. Secondly, an operator may establish a threshold for the length of an individual ILI run. The fixed costs for utilizing traditional ILI are high; however, the incremental costs for inspecting longer sections of pipeline by pressure testing or DA can be even more expensive. 4.4.2 In general, ILI and the associated repairs can be much less expensive than DA, which can require many excavations.  Also, the cost of ILI may be less than pressure testing because of the loss in revenue while the pipeline is out of service. 4.4.3 Pressure testing may be the best available option for some small diameter pipelines. ILI or DA may or may not be an alternative based on the diameter of the pipeline, inspection criteria, specific risk threats, and technology availability. Contact DA and/or ILI service providers for information regarding possible solutions and threat detection capability for a given project. Considerations for pressure testing small-diameter pipelines include whether the line may be readily taken out of service, length of the segment, availability of test medium, and other safety and environmental issues. 4.5 Piggability 4.5.1 This factor is designed to evaluate what types and the extent of physical pipeline upgrades that would be required to make a pipeline section able to allow (1) the pig to travel from start to finish without hitting blockages, and (2) operating characteristics to drive the pig at a relatively constant speed during the ILI run. When evaluating piggability, consideration should be given to how to best define the piggable section. The purpose of this consideration is to balance the desire to inspect as much of the pipeline as possible, which in turn provides the maximum benefit of obtaining integrity data while minimizing the cost per mile and limiting the number of fitting, valves, and other blockage replacements required. In general, the following are pipeline characteristics that should be considered: 

Single diameter or multi-diameter in a size range that ILI tools may negotiate;

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Blockages in the pipe section;

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Sufficient operating characteristics to drive the pig at a required speed;

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Fittings with a bend radius of less than 1.5 D;

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Pressure control/stopple fittings and all main line valves should be full port, either gate or ball valves;

All tees with greater than 50% tap sizes should be either barred or negotiable by tools without the addition of pig bars; 

No internal or offset drips that may not be removed either in service or with minimal pipeline operational disruption; 

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Cleanliness of the line;

Installation of launcher and receiver required, allowing for pipeline to be pigged (temporary launchers and receivers are options); 

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Size and length of launcher and receiver barrels;

Operationally, the pig speed should be controlled in the 1 to 3 m per second (3 to 7 mph) range for the duration of a pig run at a consistent pressure that is compatible with the cleaning and inspection tools and minimizes speed excursions. Reduced pressure and flow rates should be considered. 

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SP0113-2013 4.5.2 The use of tethered tools may limit the concerns of pipeline characteristics above; however, an outage is required for the use of tethered tools, but may not be for robotic or tractor tools. 4.5.3 The operator should also consider new technologies that may have capabilities to inspect pipelines and negotiate the obstacles and characteristics outlined above. 4.6 Shielding ECDA may not be appropriate for disbonded coatings with high dielectric constants, which can cause shielding. The ECDA survey tools are not capable of detecting coating conditions that exhibit no electrically continuous pathway to the soil. If there is an electrically continuous pathway to the soil, such as through a small holiday or orifice, tools such as DCVG or current attenuation may detect these defect areas. Refer to Table 2 in ANSI/NACE SP0502 for additional guidance. Other possible CP shielding concerns may be from rock shielding, layers of high-resistance soil, and/or plastic or other shielding material installed around the pipeline. 4.7 Corrosion Threat Excessive corrosion threats are determined by performing a risk evaluation to determine whether a pipeline with a history of corrosion repairs and/or leaks may exist. Those pipelines with excessive risk may be more desirable for being assessed by ILI vs. DA or pressure test. Such a decision could be driven by the excavation economics and/or the fact that MFL or UT tools can provide reliable data regarding remaining wall thicknesses and number of defect indications. Also, if an operator has knowledge of accelerated corrosion growth rates, that information should be considered. 4.8 Accessibility and Number of Digs The pipeline right-of-way should be evaluated to determine locations where the pipeline may not be accessed to perform aboveground surveys or to validate the results of DA modeling (deep pipeline, long cased crossings, waterways, etc.) or other situations in which the results may not be verified. Additionally, consideration should be given to the number of locations that would require validation digs when there are a large number of digs or digs where the pipeline is difficult to access. 4.9 Significant Interference Threat There may be areas in which the amount of direct current (DC) or AC stray currents may preclude the use of aboveground surveys for ECDA. In the judgment of the operator, those lines with an interference threat that is considered significant, and which cannot be effectively surveyed by using DA techniques, should be assessed using the ILI or pressure test. ILI may be preferred for cases in which the estimated corrosion rate is very high. ILI or alternative technologies should be utilized where stray current discharge points may not be identified. For those operators who cannot use ILI or pressure test and when the operator feels that the interference threat is significant, additional monitoring technologies may be implemented when ECDA indirect inspection tools are used to aid in interpreting the ECDA data. These technologies could include the use of 24-hour recording devices to capture a continuous pipe-to-soil potential at a stationary location in close proximity to the area of pipeline being surveyed or set to capture pipe-to-soil potential only during the time the survey is being performed. Stray current effects can then be better analyzed to determine their severity and possible effect on the data of the indirect inspection tool being utilized. 4.10 Seam Threat 4.10.1 An operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies, if a pipeline segment contains low-frequency electric resistance welded pipe (ERW), lap welded pipe, or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S,  Appendixes A4.3 and A4.4. For any segment in the pipeline system that has experienced seam failure or in which the operating pressure on the segment has increased over the maximum operating pressure experience d uring the preceding five years, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. Pipelines with an active seam threat should be assessed. Pressure testing shall be in accordance with ASME B31.8 at least 1.25 times MAOP. When a pressure test is not practical, the pipeline should be evaluated to determine whether ILI is a viable alternative. A candidate for such an evaluation would be one in which the ILI tool, usually circumferential or helical MFL, is capable of detecting seam cracks/flaws much smaller than expected to lead to rupture. Fitness-for-service analysis may be performed via API RP 18 579  using the material properties of the subject pipe. 4.10.2 If not feasible to perform ILI, another integrity assessment method that provides sufficient resolution of seam weld defects shall be used. However, if the line is short, 100% direct examination may be feasible.

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SP0113-2013 4.11 Other Threats The scope of this standard is limited to corrosion threats. DA, pressure testing, and selected ILI tools may be used for assessing the corrosion threat; however, the operator should also assess the pipeline for other threats such as dents, millrelated long-seam defects, gouges, and construction threats. The potential for these threats could affect the choice of corrosion assessment methodology. 4.12 Economics For short segments of pipeline that should be assessed, it may be more economical to excavate the whole length or perform DA or a pressure test rather than performing ILI on the segment. Conversely, those locations with complex or difficult excavations (i.e., highly urban locations or difficult-to-access areas) may preclude the use of DA and cause pressure testing or ILI to be more economical. 4.13 Operational Considerations Operational considerations such as a single-line system that requires constant flow to the customers may preclude modifications to a pipeline system and may dictate the use of DA rather than ILI or pressure testing, if an alternate source of gas may not be provided. 4.14 Environmental Considerations  An operator should consider the environmental impacts of each assessment technique. Such impacts may include, but are not limited to, excavation locations, accessibility, aboveground surveys, sources of water, dewatering, cleaning the water, threatened and endangered species, etc. These considerations may result in the selection of a different assessment method, based on timelines of completing the inspections or costs and damage from environmental impact. This does not exclude necessary excavations that may result from an assessment.

 _________________________________________________________________________ Section 5: Subsequent Assessments 5.1 Introduction 5.1.1 In general, the criteria used to establish the method for the first integrity assessment may be used to establish the method used for successive periodic assessments. Consideration should be given to conditions that have changed and been learned since the first or prior assessment. In addition, an operator may consider the benefits of performi ng a different assessment method to gain different or additional data to better understand the corrosion activity. For example, if an ILI is performed as a first-time assessment, an operator may decide to use an ECDA, ICDA, and SCCDA the second time to determine whether areas of metal loss found in the first assessment retain adequate corrosion mitigation protection. Data integration can improve the operator’s understanding of the pipeline’s condition. 5.1.2 In addition to the original method used for a first assessment, the decision as to what technology to utilize for the second-time assessment of a segment of pipeline must take into consideration a number of factors. Section 5 covers: 

Results of first assessment and the ongoing mitigation decisions taken;

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Feasibility of a second assessment technique using a different method;

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Changes in codes, regulations, or in operator procedures;

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Significant events between assessments leading to alternate priorities;

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Post assessment and helpful mitigation; and

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Root-cause analysis.

5.1.3 The methodology and technology selected must be that which is best suited to address the threats to a given pipeline section. The decision regarding ILI, DA, pressure testing, or the use of other technology should acknowledge the benefits

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SP0113-2013 and limitations of each in terms of pipeline safety and reliability as well as the benefits to maintenance. An operator may utilize CDA as a subsequent assessment rather than an ECDA. However, there are some limitations around the use of CDA. 5.1.4 Results of First Assessment 5.1.4.1 As pipeline segments that were inspected by ILI or DA in first assessment were calibrated and verified by direct examinations, these results should be used to provide confidence on the first-time assessment. Pressure testing does not require bell-hole inspections if the pipeline passes the pressure test. 5.1.4.2 When either ILI or DA is applied, the results of the bel l-hole inspection digs must be closely reviewed to determine whether the integrity assessment methodology operated as expected. In the case of ILI, this means within vendor provided tool tolerance. When it is determined that the previously utilized technology operated as planned, then it may show confidence in using this technology for reinspection. 5.1.4.3 Difficulties associated with implementing the first-time inspection should be closely evaluated when determining the confidence in application for a given technology to a specific pipeline. Pipe cleanliness is reviewed as part of planning for an ILI run because this can influence tool wear, integrity of data collected, and other issues that may affect 10 the success of a run. 5.1.4.4 If the DA results fail to correctly indicate the CP effectiveness relative to other areas along the pipeline, then a more direct measurement technology or different method should be considered to locate areas of concern. 5.1.5 Feasibility of Second Assessment 5.1.5.1 There are several advantages to using ECDA for the second assessment. The costs of digs may be reduced during the re-inspection because the number of digs required for a subsequent assessment may only be reduced if the mitigation program was successful. Provided the mitigation was proved effective and the bell-hole inspections yielded minimal corrosion or no corrosion (for ICDA), DA may offer the lowest-cost option for reassessment. 5.1.5.2 If ILI is used for the first assessment, the advantage of choosing ECDA is that CP performance data may be integrated to better predict long-term growth of known corrosion. If ILI was initially performed on a line because of the threat of low-frequency ERW pipe, and that threat was proved not to exist, ECDA may become a viable option. However, other factors such as the possibility of third-party damage and ROW encroachment should be considered. 5.1.5.3 If ILI is used for the first assessment, there are several advantages to using ILI for the second assessment. Costs are reduced significantly because the impediments have been removed and the pipeline upgraded, the internal bore has been proved, and less cleaning should be required. If a special crack detection pig was used initially to assess low-frequency ERW pipe and no actual threat was discovered, a standard, less expensive MFL tool may be considered. ILI provides an opportunity to perform a run-to-run comparison to determine corrosion growth rates for specific anomalies. 5.1.5.4 If DA is used for the first assessment, switching to ILI offers several advantages. Data from both assessment methodologies should be integrated to determine current and predicted future locations and corresponding anomaly sizing. If the segment to be assessed increased in length after the original ECDA inspection, ILI becomes a more cost-competitive option for reassessment. However, pipeline modifications resulting from increased length should be considered to ensure feasibility. 5.1.5.5 If the first ECDA inspection proved the existence of shielding, ILI may be the better choice for redoing the original assessment and also for the reassessment because the pipeline might contain extensive corrosion. 5.1.5.6 If pressure testing is used for the first assessment, the use of DA or ILI for the second assessment can provide additional information on the feasibility of any monitoring and mitigation that has been implemented since the first assessment. If pressure testing is used for the subsequent assessments, it validates that no anomaly has grown to the point of failure. However, the pressure test does not provide any additional information that can be integrated with future monitoring and mitigation activities. 5.1.5.7 If pressure testing is used for a subsequent assessment after a DA or ILI assessment, it validates that no anomaly has grown to the point of failure.

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SP0113-2013 5.1.5.8 The use of consecutive ILI runs can provide the cumulative wall loss over time at various locations. If aboveground surveys are integrated with the ILI data, a measure of CP performance might be a better way to manage integrity. 5.1.6 Changes in Codes, Regulations, or Operator Procedures When a pipeline, or pipeline segment, is assessed under an operator’s integrity management program, it should be reassessed to comply with the most current codes, regulations, standards, and interpretations. Before choosing the assessment method, a pipeline segment should be pre-assessed the second time. An operator should compare the codes, regulations, standards, and interpretations that were in place during the first assessment with the current codes, regulations, standards, and interpretations that are in place. If there are any differences, then the feasibility of the assessment must be analyzed to choose the more practicable integrity assessment. 5.1.7 Significant Events Between Periodic Assessments 5.1.7.1 Significant events between assessments should be considered in the pre-assessment step when an assessment method is selected. If a leak or a rupture is present, the reinspection interval should be immediately reevaluated. Significant events include, but are not limited to: 5.1.7.1.1 Events that may cause new threats to be identified, a threat level to increase, or existing stable threats to become unstable. An example would be a pipeline failure caused by IC or SCC on a line that did not have IC or SCC identified as a threat requiring assessment. A second example could be a manufacturing threat activated by a pressure excursion on a low-frequency ERW pipeline or a seam leak on the same type of pipe. 5.1.7.1.2 Events that may cause new threats to be identified, a threat level to increase, or existing stable threats to become unstable. An example would be a pipeline failure caused by IC or SCC on a line that did not have IC or SCC identified as a threat now requiring an immediate integrity reassessment. Previously unknown threats trigger an immediate reassessment of the pipeline because the assumptions in the original assessment are questioned. 5.1.7.1.3 Corrosion leaks along the pipeline not anticipated subsequent to the first assessment (i.e., the corrosion rate is higher than predicted). When a leak occurs prior to the next assessment, a root-cause analysis should be performed. If the reason for the leak is a result of an inadequacy of the assessment method to accurately detect the kind or size of defect that caused the failure, alternate assessment methods must be implemented immediately. In addition, if a leak occurs after a pressure test was used as an assessment method, an operator should consider (9) whether the leak was caused by a threat that interacted with a manufacturing defect. See U.S. DOT  Final Report 19 No. 05-12R for more details. 5.1.7.1.4 Changes in operating pressure or pipe replacements that were not foreseen or in effect at the time of the first assessment. In some cases, pigging deemed to be infeasible because of inadequate pressure or piping geometry issues should be reviewed again as a viable assessment technology when operating or construction barriers are removed. 5.1.8 Post Assessment and Mitigation The adequacy of the first assessment shall be determined in the post-assessment phase for any integrity assessment and required for DA and ILI. If the first-time assessment tool identifies significant areas in need of mitigation or remediation, then the specific mitigation activities chosen could affect the assessment tool selection for the second assessment. Mitigation activities include large recoat projects, and installation of supplemental CP sources (including point source as well as linear arrays of anode beds), etc. Supplemental or increased CP does not typically provide adequate protection under CP shielding conditions. Mitigation activities completed after the first assessment may limit the effectiveness of a subsequent assessment. In addition, mitigation that is performed after the first assessment should lower or eliminate specific threat levels, which could drive another assessment method to be selected. 5.1.9 Root-Cause Analysis The root-cause analysis documents specific reasons for corrosion at a specific location or locations. The presence of corrosion damage caused by types of shielding, including shielding coatings, rock impingement, rock ledges, or other geologic conditions should be candidates for ILI inspection. Note that although currently there is no way to detect shielding with ECDA, a modified technique is currently being undertaken. Additionally, the presence of MIC as the root (9)

 Department of Transportation (DOT), 1200 New Jersey Ave. SE, Washington, DC 20590.

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SP0113-2013 cause or as a contributor to the root cause should be a consideration for second-time tool selection, as the presence of MIC increases the polarization requirements necessary to prevent external corrosion and suggests the use of ECDA. The root cause for any hydrotest failures should be determined to establish whether other assessment methods are better suited for helping to identify the specific cause of the failure.

 _________________________________________________________________________ References 1.  ANSI/ASME B31.4 (latest revision), “Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids” (New York, NY: ASME). 2.  ANSI/ASME B31.8 (latest revision), “Gas Transmission and Distribution Piping Systems” (New York, NY: ASME). 3.  ANSI/ASME B31.8S (latest revision), “Managing System Integrity of Gas Pipelines” (New York, NY: ASME). 4.  API Standard 1160 (latest revision), “Managing System Integrity for Hazardous Liquid Pipelines” (Washington, DC: API). 5. ANSI/NACE SP0502 (latest revision), “Pipeline External Corrosion Direct Assessment Methodology” (Houston, TX: NACE). 6.

NACE SP0210 (latest revision), “Pipeline External Corrosion Confirmatory Direct Assessment” (Houston, TX: NACE).

7. NACE SP0206 (latest revision), “Internal Corrosion Direct Assessment Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)” (Houston, TX: NACE). 8. NACE SP0110 (latest revision), “Wet Gas Internal Corrosion Direct Assessment Methodology for Pipelines” (Houston, TX: NACE). 9. N ACE SP0208 (latest revision), “Internal Corrosion Direct Assessment Methodology for Liquid Petroleum Pipelines” (Houston, TX: NACE). 10. NACE SP0102 (latest revision), “In-Line Inspection of Pipelines” (Houston, TX: NACE). 11. API 1163 (latest revision), “In-line Inspection Systems Qualification Standard” (Washington, DC: API). 12. NACE Publication 35100 (latest revision), “In-Line Nondestructive Inspection of Pipelines” (Houston, TX: NACE). 13. ANSI/API RP 1110 (latest revision), “Pressure Testing of Liquid Petroleum Pipelines” (Washington, DC: API). 14. NACE SP0204 (latest revision), “Stress Corrosion Cracking (SCC) Direct Assessment Methodology” (Houston, TX: NACE). 15. ANSI/ASNT ILI-PQ (latest revision), “In-Line Inspection Personnel Qualification and Certification” (Columbus, OH: ASNT, 2005). 16. GRI 00/0192, “GRI Guide for Locating and Using Pipeline Industry Research” Section 4, Hydrostatic Testing (Des Plaines, IL: GRI). 17. Work in progress by PRCI PR003-9523, “Alternatives to Pre-ser vice Hydrotesting of Pipelines” (Falls Church, VA: PRCI). 18. API RP 579 (latest revision), “Recommended Practice for Fitness-for-Service” (Washington, DC: API). 19. J.F. Kiefner, “Evaluating the Stability of Manufacturing and Construction Defects in Natural Gas Pipelines ,” U.S. Department of Transportation, Final Report No. 05-12R, April, 2007.

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SP0113-2013  _________________________________________________________________________ Bibliography “Spike Hydrostatic Test Evaluation.” Department of Transportation. OPS TT06 Final Report. July 2004. U.S. Code of Federal Regulations (CFR) Title 49. “Protection Against Accidental Overpressure.” Part 192. Washington, DC: Office of the Federal Register, 1992. U.S. Code of Federal Regulations (CFR) Title 49. “Protection Against Accidental Overpressure.” Part 195. Washington, DC: Office of the Federal Register, 1995.

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ISBN 1-57590-259-1 NACE International