Api rp 1160 2013 (american petroleum institute)

The program involves defining the critical locations along the pipeline and near pipeline facilities that would be most affected by an unintended release, defining the threats to the int

Terms and Definitions

For the purposes of this document, the following definitions apply.

An anomaly that may exceed acceptable limits based on the operator’s anomaly and pipeline data analysis (see API 1163).

A possible deviation from sound pipe material or weld See also defect and imperfection.

NOTE 1 Indication may be generated by nondestructive inspection, such as in-line inspection (NACE 35100)

NOTE 2 Alternatively: An unexamined deviation from the norm in pipe material, coatings, or welds (API 1163)

A written plan produced by the operator that as a minimum:

1) identifies all segments of a pipeline system that could impact a critical location;

2) identifies the specific integrity assessment method(s) to be applied to those segments;

3) specifies the schedule by which those integrity assessments will be performed; and

4) provides the technical justification for the selection of the integrity assessment method(s) and the risk basis for establishing the assessment schedule.

NOTE This includes baseline assessment plans.

Technique by which underground metallic pipe is protected against external corrosion.

A valve that permits fluid flow in only one direction

NOTE Should the direction of flow reverse (e.g after a failure), the valve contains a mechanism that automatically prevents flow in the opposite direction.

Locations such as populated areas, commercially navigable waterways, drinking water resources, or ecologically sensitive areas See also high consequence area.

3.1.8 current established maximum operating pressure

The maximum operating pressure (MOP) of a pipeline can differ from its design MOP, as the current MOP may be adjusted for reasons such as derating the pipeline.

Pressure in a piping system is defined as the total of static head pressure, the pressure needed to counteract friction losses, and any existing back pressure This pressure is measured at any point in the system while it operates under steady state conditions For further reference, see the maximum steady state operating pressure illustrated in Figure 1.

An imperfection of a type or magnitude exceeding acceptable criteria (API 570); alternatively, a physically examined anomaly with dimensions or characteristics that exceed acceptable limits (see API 1163) See also anomaly and imperfection.

Figure 1—Schematic of Various Pipeline Pressures

CEMOP current established maximum operating pressure

MSSOP maximum steady state operating pressure NOP normal operating pressure

At any location in a pipeline, the maximum allowable steady state operating pressure must be greater than or equal to the static head pressure present at that point under static conditions, as outlined in ASME B31.4-2009, Paragraph 401.2.2.

Integrity assessment processes are essential for identifying time-dependent degradation in pipelines due to external corrosion, internal corrosion, or stress corrosion cracking These processes involve specific measurements and analyses, as well as excavating the pipeline when necessary to evaluate its condition Key methods include external corrosion direct assessment, internal corrosion direct assessment, and stress corrosion cracking direct assessment.

The discovery of a condition arises when an operator gathers enough information to identify a potential threat to the pipeline's integrity Operators are required to obtain this information promptly, ideally within six months following an integrity assessment, unless they can prove that adhering to this timeframe is impractical.

3.1.14 double submerged arc welded pipe

Pipe that has a straight longitudinal or helical seam containing filler metal deposited on both sides of the joint by the submerged-arc process.

Pipe that has a straight longitudinal seam produced without the addition of filler metal by the application of mechanical force and heat obtained from electric resistance.

See check valve or remotely controlled valve.

The integrity assessment process involves identifying potential external corrosion, coating damage, or cathodic protection deficiencies in pipelines through aboveground measurements, followed by excavations to inspect the pipe as needed, in accordance with NACE SP0502 standards.

3.1.18 final in-line inspection report

A report provided by the ILI vendor that provides the operator with a comprehensive interpretation of the data from an ILI See also preliminary in-line inspection report.

A technique for detecting anomalies in a pipeline that involves introducing mechanical stress waves that propagate axially from a circumferential array of low-frequency transducers placed around the pipeline at a fixed location

The pipe's wall thickness acts as a wave guide, allowing for the detection of anomalies based on the timing of reflected waves returning to the emitting device.

NOTE 2 The technique is applicable for distances up to several hundred feet.

The heat-affected zone of an ERW seam that has a high hardness as the result of inadequate postweld heat treatment.

A localized increase in hardness through the thickness of a pipe, produced during hot rolling as a result of localized quenching.

Those locations where a pipeline release might have a significant adverse effect on an unusually sensitive area (see

49 CFR 195.6), a high population area, an other populated area, or a commercially navigable waterway

NOTE This definition is specific to the federal regulations in the United States, see 49 CFR 195.

A form of cracking that may occur in line pipe steels that contain manganese sulfide inclusions when such steels are used in sour service.

Localized cracking can occur in hard spots or heat-affected zones of line pipe steel when exposed to atomic hydrogen produced by cathodic reactions at the pipe's surface.

A method for evaluating the integrity of both new and existing pipelines, as outlined in API 1110, involves filling the pipeline with water and pressurizing it to a level well above the Maximum Operating Pressure (MOP) This process ensures that the pipeline is suitable for service at its designated MOP.

NOTE The test pressure is held for a period of time to establish that the pipeline is free of leaks.

During engineering and inspection analysis, a flaw or discontinuity identified may need to meet specific acceptance criteria as outlined in API 570 Alternatively, an anomaly may be present that does not exceed acceptable limits, as referenced in API 1163 For further context, see the definitions of anomaly and defect.

Nondestructive testing techniques, such as those outlined in NACE 35100, or signals from an In-Line Inspection (ILI) system, can reveal critical findings These indications can be further categorized as anomalies, imperfections, or defects, as referenced in API 1163.

An inspection of a pipeline from the interior of the pipe using an ILI tool.

A method for determining the pipe's current condition Methods include ILI, pressure testing, direct assessment, or other technologies that can demonstrate the integrity of the pipe.

A documented set of policies, processes, and procedures that includes, at a minimum, the following elements:

— a process for determining which pipeline segments could affect a critical location;

— a process for continual integrity assessment and evaluation;

— an analytical process that integrates relevant information about pipeline integrity and the consequences of a failure;

— repair criteria to address issues identified by the integrity assessment method and data analysis (49 CFR 195.452 provides minimum repair criteria for certain, higher-risk, features identified through internal inspection);

— a process to identify and evaluate preventive and mitigative measures to protect critical locations;

— methods to measure the integrity management program’s effectiveness;

— a process for review of integrity assessment results and data analysis by a qualified individual.

An integrity assessment process conducted for the purpose of locating and remediating anomalies arising from internal corrosion of a pipeline (see NACE SP0208).

The MOP that a pipeline or segment of a pipeline may be normally operated under 49 CFR 195 (see Figure 1).

3.1.33 maximum steady state operating pressure

In a piping system operating under steady state conditions, the total pressure is the sum of the static head pressure, the pressure needed to counteract friction losses, and any back pressure present at each point, as outlined in ASME B31.4-2009, Paragraph 401.2.2.

NOTE The MSSOP is limited by physical controls on the pipeline such as discharge pressure, relief pressure, shutdown settings, etc (see Figure 1).

To mitigate pipeline integrity risks, it is essential to take appropriate actions based on a thorough assessment of risk factors This approach aims to lower the overall risk by addressing both the probability of incidents and their potential consequences.

The anticipated pressure in a piping system, which includes the total static head pressure, the pressure needed to counteract friction losses, and any back pressure, is determined at various points while the system functions under specific predicted steady state conditions.

A person who owns or operates pipeline facilities (49 CFR 195).

A section of piping that has all points exposed to an environment of similar threat state and that is of similar design conditions and construction material (adapted from API 570).

3.1.38 preliminary in-line inspection report

A report generated quickly that highlights anomalies posing immediate risks to pipeline safety is essential for operators For further details, refer to the final in-line inspection report.

NOTE Typically, the operator defines the actual reporting parameters

Activities designed to reduce the likelihood of a pipeline failure (preventive) and/or minimize or eliminate the consequences of a pipeline failure (mitigative)

Acronyms and Abbreviations

CEPA Canadian Energy Pipeline Association

DC-ERW direct current welded electric resistance welding

DIRT Damage Incident Reporting Tool

DSAW double submerged arc welding

ECDA external corrosion direct assessment

EFRD emergency flow restriction device

GWUT guided wave ultrasonic testing

HF-ERW high-frequency welded electric resistance welding

HSAW helical seam double submerged arc welding

ICDA internal corrosion direct assessment

LF-ERW low-frequency welded electric resistance welding

MSSOP maximum steady state operating pressure

PPTS Pipeline Performance Tracking System

SCADA supervisory control and data acquisition

SCCDA stress corrosion cracking direct assessment

SOHIC stress-oriented hydrogen-induced cracking

General Considerations

A pipeline integrity management program is essential for ensuring that operators take timely and appropriate actions to minimize risks to the public, employees, the environment, and customers This document serves as a guideline for pipeline operators in the development of their pipeline integrity management plans (IMPs).

In simplest terms a pipeline integrity management program should:

— identify threats to pipeline integrity,

— identify potential consequences to the public and the environment in the event of a release,

— rank segments of the pipeline system according to the risk each poses,

— provide for assessment of the integrity of each segment in a timely manner based on identified threats and the risk to minimize the possibility of a release,

— specify repairs or mitigative actions to carry out in a timely manner to prevent releases,

— define preventive and mitigative measures to address relevant threats including those not covered by integrity assessments,

— use the findings of integrity assessments to update and improve the integrity management process.

The program process flow illustrated in Figure 2 outlines a standardized framework for creating an operator-specific integrity management program This program entails a continuous cycle of monitoring pipeline conditions, identifying and assessing risks, and implementing actions to mitigate the most significant threats To optimize resource allocation and ensure error-free, spill-free operations, risk assessments must be regularly updated to reflect current conditions.

Elements of Integrity Management

The program focuses on identifying pipeline segments that may impact critical locations in the event of a release This process includes evaluating populated areas, environmentally sensitive regions, and navigable waters, while integrating this data with pipeline mapping It is essential to determine where a release could affect these critical locations, which may change over time or with modifications to the pipeline system Regular reviews of these critical locations are necessary, and guidance for these assessments can be found in Section 5 of this RP.

To assess potential threats to pipeline integrity and the impact of possible spills on critical locations, operators must gather, review, and integrate essential information This includes pipeline design, attributes, operational history such as pressure ranges and past incidents, results from previous inspections and assessments like in-line inspections (ILIs) or hydrostatic tests, records of repairs and mitigative actions, corrosion and cathodic protection surveys, and preventive measures against releases.

Operators can access the key components of integrity management mandated by 49 CFR 195.452 at http://primis.phmsa.dot.gov/iim/flowchart1.htm This includes the integration of relevant industry trends, regulatory updates, and insights from other operators Additionally, Section 6 summarizes the data sources, common data elements used in risk analyses, and methods for data review and integration.

Risk assessment involves utilizing data gathered from earlier stages to evaluate the pipeline system's vulnerabilities This process starts with a thorough and methodical examination of potential threats that could compromise the integrity of the pipeline or facility.

The pipeline industry through the Pipeline Research Council International (PRCI) has classified pipeline incidents into

Pipeline integrity management involves addressing 22 distinct categories of threats to ensure the safety and reliability of pipeline systems Each category represents a specific risk that must be evaluated and mitigated based on its relevance to individual pipeline segments.

Figure 2—Process Flow for an Integrity Management Program

Has baseline assessment been conducted?

Identify potential impact to critical locations (Section 5)

Conduct initial data gathering, review, and integration (Section 6)

Conduct initial risk assessment (Section 7)

Integrate data from previous assessment(s), review elements used previously, and update as needed (Section 6)

Review and update potential impact to critical location (Section 5)

Reassess risk using data from previous assessments (Section 7)

Are modifications to plan required?

Modify plan as necessary (Section 8)

Implement assessment and/or mitigation (Sections 8 and 9)

Follow continuing assessment plan (Section 8)

Assess pump stations and terminals (Section 11)

6) defective pipe girth weld (circumferential including branch and T joints);

9) stripped threads/broken pipe/coupling failure;

13) miscellaneous (failure of valve or other component);

14) damage inflicted by first, second, or third parties (instantaneous/immediate failure);

15) previously damaged pipe such as dents and/or gouges (delayed failure);

22) unknown (root cause of failure was not determined).

ASME B31.8S advises pipeline operators to incorporate the first 21 of the 22 identified threats into their Integrity Management Programs (IMPs) The "unknown" threat (Threat 22) is excluded from this list, as it is impossible to prevent or mitigate an unidentified risk According to ASME B31.8S, these 21 threats are categorized into time-dependent, stable, or time-independent groups, with specific failure modes classified under each category.

— welding/fabrication related threats: defective pipe girth welds, defective fabrication welds, wrinkle bends and buckles, and stripped threads/broken pipe/coupling failure;

— equipment threats: gasket or O-ring failure, control/relief equipment malfunction, seal/pump packing failure; and

— third-party/mechanical damage threats: damage inflicted by first, second, or third party (instantaneous/immediate failure);

— weather-related and outside force threats: cold weather, lightning, heavy rains or floods, and earth movement.

Operators of hazardous liquid pipelines must incorporate specific threats into their Integrity Management Programs (IMPs) Due to the distinct physical and regulatory differences between gas and liquid pipelines, it is essential to modify threat categories accordingly Notably, liquid pipelines face a significantly higher risk of pressure-cycle-induced fatigue compared to gas pipelines This increased risk introduces an additional threat category, as various defects may worsen due to pressure-cycle-induced fatigue, necessitating careful consideration by liquid operators.

49 CFR 195 mandates a focused evaluation of seam integrity for specific seam types, leading to the classification of selective seam corrosion as a distinct threat category, as outlined in ASME B31.8S Additionally, the issue of "transit fatigue" is recognized as a significant concern in hazardous liquid pipelines, stemming from fatigue induced by pressure cycles.

The threats for hazardous liquid pipelines that operators should address can be characterized as follows:

3) selective seam corrosion (external or internal);

5) manufacturing defects (defective pipe seams including hard heat-affected zones and defective pipe including pipe body hard spots);

6) construction and fabrication defects (including defective girth welds, defective fabrication welds, wrinkle bends and buckles, and stripped threads/broken pipe/coupling failure);

7) equipment failure (including gasket or O-ring failure, control/relief equipment failure, seal/pump packing failure, and miscellaneous);

8) mechanical damage (causing an immediate failure or from vandalism);

9) mechanical damage (previously damaged pipe causing a delayed failure or vandalism);

11) weather and outside force (cold weather, lightning, heavy rains or floods, and earth movement);

12) the growth of an initially noninjurious anomaly arising from any one of several of the above causes into an injurious defect via pressure-cycle-induced fatigue (including transit fatigue).

Time-dependent threats, specifically threats 1), 2), 3), 4), and 12), necessitate regular assessment and monitoring Threats 5), 6), and 9) are potentially time-dependent due to the risk of expansion from pressure-cycle-induced fatigue, requiring pipeline operators to evaluate the need for ongoing assessments In contrast, threats 7), 8), 10), and 11) are classified as time-independent, as they pertain to unpredictable random events Effective management of these threats involves implementing preventive and mitigative strategies.

Not all 12 identified threats are relevant to every hazardous liquid pipeline, and operators may choose to tailor their strategies for addressing these risks A detailed discussion of these 12 threats can be found in Annex A of this RP.

Assessing the potential consequences of a release is crucial, particularly regarding impacts on critical locations Risk is defined as the combination of the probability of an event and its consequences, which can vary along different points of a pipeline Therefore, risk assessment should be conducted incrementally or by discrete segments to prioritize and rank them effectively It is essential to periodically reassess risk, especially before evaluating pipeline integrity, while considering information from previous assessments Guidance for developing and implementing a risk assessment approach is provided in Section 7.

The pipeline operator must create or update a Pipeline Integrity Assessment Plan, prioritizing assessments based on risk rankings from previous evaluations, starting with the highest risks The plan should specify the internal inspection techniques, pressure testing, or other technologies to be used for assessing pipeline integrity, particularly for segments impacting critical locations Additionally, it should outline the assessment schedule, justify the chosen integrity assessment methods, and detail the mitigative measures to be implemented Guidance for conducting these assessments is available in Section 8, while Annex B describes various internal inspection techniques and offers assistance in selecting appropriate assessment methods.

Pipeline operators must implement a comprehensive integrity assessment plan to evaluate and address anomalies that threaten pipeline integrity promptly For segments impacting critical locations, it is essential to set reasonable time limits for examining various anomalies detected by In-Line Inspection (ILI), while adhering to relevant regulatory requirements Guidance on prioritizing ILI-identified features for examination and repair is provided in Section 8, and Annex C outlines commonly used repair techniques for addressing different defect types discovered during the integrity assessment.

Pipeline operators must periodically revise their Integrity Assessment Plan to ensure ongoing safety and compliance A reassessment schedule should be developed, taking into account deterioration rates, potential event consequences, and various risk factors Guidelines for scheduling these reassessments are outlined in Section 9, with practical examples for calculating reassessment intervals available in Annex D.

Pipeline operators must establish and implement a systematic process to assess the necessity for additional protective measures This proactive approach ensures the safety and integrity of pipelines, incorporating various potential strategies to mitigate risks effectively.

General

Pipeline integrity management aims to minimize risks to the public, employees, the environment, and customers Therefore, pipeline operators must prioritize the inspection, evaluation, and maintenance of segments located near critical areas where spills could have significant consequences Commercial software, including geographic information system (GIS) technology, is available from various service providers to assist in these tasks This technology plays a crucial role in gathering information about pipeline segments and facilities that may impact critical locations, which is essential for an effective integrity management program.

— decisions on placement of EFRDs,

— installation and utilization of leak detection systems,

— development and implementation of spill response plans.

Determining Whether a Release from a Pipeline Segment or a Facility Could Affect a Critical

When gathering data and integrating information into a pipeline Integrity Management Program (IMP), operators must assess the potential impact of a pipeline segment or facility, such as a pump station or delivery terminal, on critical locations in the event of a release It is essential to evaluate not only the critical locations near the segment or facility but also those that the pipeline segment intersects Key considerations for determining a potential impact zone include proximity to critical locations and the characteristics of the pipeline segment.

1) the proximity of the pipe to identified critical locations;

2) the nature and characteristics of the product or products transported [refined products, crude oil, highly volatile liquids (HVLs), etc.];

3) the operating conditions of the pipeline (pressure, temperature, flow rate, etc.);

4) the topography of the land associated with the critical location and the pipeline segment;

5) the hydraulic gradient of the pipeline;

6) the diameter of the pipeline, the potential release volume (including drain out), and the distance between isolation points;

7) the type and characteristics of the critical location crossed or in proximity to the segment;

8) potential physical pathways between the pipeline and the critical location, including overland spread, water transport by streams and rivers, or air dispersion in the case of an HVL;

9) response capability (time to detect, confirm, and locate a release; time to respond; nature of the response; etc.).

An outline of the process is shown in Figure 3

5.2.2 Identifying Segments or Facilities Located Within Critical Locations

The operator must compare the pipeline's route with a relevant map of the critical location to determine where the segment enters and exits Additionally, any facilities within the critical location's boundaries should be identified This analysis will pinpoint the segments or facilities that could directly impact the critical location in the event of a release.

When defining the boundaries of critical locations, it is essential to consider the potential product release, the methods of dispersion, and the risks of personal injury or property damage from a spreading plume in soil, air dispersion of high vapor liquids (HVL), surface pooling, or fire and explosion hazards Additionally, it is important to account for any possible inaccuracies in the boundary locations.

5.2.4 Identifying Segments or Facilities That Could Affect a Critical Location When Such Segments or Facilities Are Not Located Within the Boundaries of the Critical Location

A release from a pipeline segment or facility can impact a critical location even if it lies outside its boundaries Operators must assess how released products or their effects can reach these critical areas, considering transportation methods such as overland spread, water movement, or aerial vapor dispersion Additionally, the potential for widespread ignition or explosion effects should be taken into account, as well as the possibility of product being sprayed into the air.

Operators should utilize topographical maps and local knowledge to evaluate potential scenarios where released products could reach critical areas Each scenario must consider possible releases from various points along the pipeline or from key facilities, such as breakout tanks It is essential to assess multiple release points at reasonable intervals along the pipeline Any point identified as capable of transporting product to a critical location must be marked, as well as any facility where a release could similarly impact these critical areas.

Factors for consideration in establishing release scenarios include the following:

— topography and volume of drain out;

— internal pressure and its effect on spraying product into the air;

Figure 3—Identifying Pipeline Segments or Facilities That Could Affect Critical Locations

Consider airborne spraying of product.

Conduct air dispersion analysis for HVL segments.

Consider the potential for product being transported through sewers, ditches, drains, and field-drain tiles.

Use topographical maps and population data to define critical locations.

Determine segments or facilities located within critical locations.

Periodically review and update boundaries of critical locations

Consider overland spread and water pathways for product to reach critical locations.

Determine segments or facilities that could affect critical location even if not within the boundaries of critical location.

Establish release points on segments or at facilities for hypothetical releases and calculate spill volumes.

— tank volume for tanks at facilities;

— time to detect a large release such as a rupture;

— time to detect a small release such as a leak that is just at the threshold of the leak-detection system;

— time to isolate the segment or facility;

— time for gravity drain-down to occur;

— viscosity and vapor pressure of the product;

— water pathways (surface and underground);

— ditches, sewers, and drain tiles;

— wind direction for aerial dispersion;

— porosity and permeability of soil.

Additional considerations for HVLs include the following:

— aerial dispersion analysis for an HVL vapor cloud;

— effect that a vapor cloud fire, a pool fire, or a vapor cloud explosion would have on the critical location.

Documentation and Updating

Operators must document all pipeline segments and facilities that may impact critical locations and provide supporting analyses to subject matter experts (SMEs) for risk assessments and integrity prioritization Regular reviews should be conducted to identify any changes in these segments or facilities Additionally, operators can implement a process to detect changes during routine operations and maintenance activities, such as aerial patrols and right-of-way maintenance Any newly identified segments or facilities should be incorporated into the existing documentation affecting critical locations.

6 Gathering, Reviewing, and Integrating Data

Section 6 aims to outline key considerations for identifying and utilizing data to effectively manage integrity threats in pipeline systems This approach acknowledges that users of this RP possess various data sources related to their pipeline systems, which are currently managed through established processes Nonetheless, for the purpose of integrity management, it may be necessary to collect and organize this data in a different manner.

Ensuring high data quality and consistency is crucial for effective analysis Operators must collect reliable data to support their analyses, and when data is insufficient, the risk process must address the resulting uncertainty While default values may be used in the absence of actual data, it is essential to prioritize the acquisition of real data and clearly identify when default values are applied.

The analyst should avoid the temptation to make assumptions in the absence of data and should consider the benefit of gathering missing information.

To effectively identify potential threats to the integrity of the pipe, it is essential to gather and integrate high-quality and comprehensive data for risk assessment This data should encompass various relevant factors that could impact the pipe's safety and performance.

— the attributes of each pipeline segment that bear on the susceptibility to various integrity threats,

— construction factors that could affect the susceptibility to various integrity threats,

— operating parameters that could affect the susceptibility to various integrity threats,

— assessment histories that may indicate susceptibility to various integrity threats,

Data Integration

Data integration involves combining multiple data sets to identify significant conditions along a pipeline, utilizing sources such as ILI, cathodic protection surveys, and depth of cover measurements Advanced applications may employ software to spatially align and correlate this data For instance, overlaying ILI data from different tools can reveal insights, such as a metal loss anomaly coinciding with a geometric anomaly, indicating potential mechanical damage rather than corrosion This prompts operators to investigate further, even if the metal loss alone wouldn't typically warrant it Additionally, integrating ILI data with aerial surveillance records can uncover mechanical damage, as seen when utility installations near a right-of-way corresponded with identified anomalies.

Data Maintenance

The data elements essential for evaluating a threat's relevance and potential failure can evolve over time due to factors such as alterations in operating practices, shifts in land use, and new pipe properties from replacements or reroutes Pipeline operators must remain vigilant to these changes and ensure that the data utilized for threat and risk assessments accurately represent the pipeline's current conditions.

Types of Data Used to Assess Risk

Data used to evaluate threats and risks to pipeline segments or facilities can be classified into four main categories: pipe attributes, construction factors, operating parameters, and assessment history.

Pipeline attributes are typically contained on alignment sheets or system maps The following is a representative list of these data elements:

— type of pipe (seamless, low-frequency or DC welded ERW seam, high-frequency welded seam, single or double submerged arc welded seam, FW seam);

— valve locations, types, and performance characteristics;

— types and locations of appurtenances, flanges, fittings, dead-legs, and instrumentation lines;

— locations of pump stations, booster stations, and terminals;

— highway and road crossings, cased and uncased;

— river, creek, and lake crossings;

— pipeline and other utility crossings, shared rights-of-way.

Construction factors can typically be sourced from design, and construction, records The following is a representative list of these data elements:

— coating installation method (over-the-ditch versus factory coating of pipe and field coating of joints);

— soil type (sand, silt, clay, rock);

— width of right-of-way;

— special protection (directional drills, concrete coating, barriers, warning strips).

Pipeline operating data elements are documented in the operator's "operation and maintenance" manuals, "standard operating procedures," and training materials Additional data, including pressure histories, test lead survey reports, valve inspection reports, river crossing inspection reports, and records from aerial or ground patrols, are found in operating and maintenance records Key data elements include these various reports and inspection records.

— SCADA and leak detection attributes;

— aerial and ground patrol frequencies;

— qualifications and training of operators;

— failure investigations, incident reports, near-miss reports, soil and water sampling reports, corrosion coupons and resistance measurements;

Pipeline Integrity assessments will be contained in documents describing specific tests or inspections and the results The following is a representative list of these data elements:

— pressure levels achieved in previous hydrostatic test and test failure history;

— anomaly lists from previous ILIs along with disposition of anomalies;

The results of supplementary evaluations, including close-interval pipe-to-soil potential surveys, DCVG surveys, pipeline current surveys, soil resistivity surveys, direct visual inspections of the pipeline and its coating, right-of-way condition surveys, and depth-of-burial surveys, are crucial for assessing pipeline integrity and ensuring safety.

— previous repair types and practices.

Risk to a liquid pipeline system is determined by the likelihood of damage from various threats and the potential consequences of a release at critical locations It is quantified as the product of the probability of a release and its consequences, with higher values indicating greater risk By evaluating risk across the pipeline, operators can categorize and prioritize locations, enabling effective allocation of resources for risk mitigation Risk can be assessed in relative terms, comparing it to other identified risks, or in absolute terms, focusing on the expected consequences of specific risk elements.

When creating a risk assessment approach, it is crucial to recognize its intended purpose Risk assessments guide the selection and sequencing of integrity assessments and the implementation of preventive and mitigative actions The design of the risk assessment should focus on identifying relevant threats to the asset and prioritizing subsequent activities accordingly.

Figure 4—Simplified Depiction of Risk

Developing a Risk Assessment Approach

The goals of risk assessment are as follows:

— to identify the threats to pipeline integrity;

— to determine the risk represented by these threats and the consequences to critical locations;

— to rank segments of a pipeline system in the order of greatest need for integrity assessment or mitigative action;

— to compare different integrity assessment or mitigation options in terms of the risk reduction benefits and costs;

— to facilitate reassessment and reranking once the integrity assessments and mitigative actions have been completed.

A pipeline risk assessment process should address the following questions.

1) What kind of events and/or conditions might lead to a loss of system integrity?

2) How likely, in a relative or absolute sense, are these events and/or these conditions to occur?

3) What are the nature and the severity of the consequences if these events and/or conditions occur?

4) What risks are associated with these events and/or conditions either in a relative sense and/or an absolute sense?

There are various methods for implementing a risk process, each capable of addressing key questions The complexity of these methods depends on the asset's intricacy, the data required, and the quality and quantity of available data Engaging subject matter experts (SMEs) is essential for designing and executing effective risk processes, regardless of the chosen approach.

Subject Matter Experts (SMEs) play a crucial role in ensuring pipeline integrity, leveraging their extensive experience in areas such as design, construction, and risk management They possess in-depth knowledge of pipeline systems, including critical locations and applicable threats to integrity By evaluating each pipeline segment, SMEs assess risks and rank segments for integrity assessments While they may consult external experts, they primarily rely on technical literature and industry data to inform their evaluations.

Relative risk assessment involves developing or purchasing an arithmetic model to calculate numerical scores for pipeline segments based on identified threats to integrity and critical locations that could be impacted by a release These models utilize equations that incorporate relevant parameters, often multiplied by validated weighting factors from sensitivity studies and historical comparisons They provide algorithms to determine the risk score for each threat and assess the effects of integrity evaluations and mitigation strategies This allows for a comparison of potential integrity assessment methods and mitigative actions before implementation The resulting scores enable the ranking of pipeline segments by relative risk, prioritizing the highest-risk sections for assessment and mitigation After completing assessments, segments can be reranked, facilitating informed planning for subsequent evaluations.

Scenario-based models assess the risk of releases by analyzing events and their sequences, assigning probabilities based on historical occurrence rates A fault tree is created to illustrate the interactions of these events, leading to a calculated probability of a release for each of the 13 threats relevant to specific pipeline segments This model also evaluates the likelihood of different types of releases impacting critical locations and the associated costs By multiplying the probability of a release at a critical site by the potential damage and cleanup costs, operators can derive an "expectation" in cost terms for each scenario Ultimately, operators calculate expectations for all relevant scenarios to prioritize which pipeline segments require immediate integrity assessment.

Probabilistic Risk Assessment (PRA) involves evaluating the likelihood of adverse events, such as pipeline pressure drops below the Maximum Operating Pressure (MOP) in critical areas, alongside their associated costs This method necessitates thorough integrity assessments for pipeline segments where the calculated risk—derived from the probability and cost of undesirable events—exceeds acceptable thresholds Effective PRA relies on substantial, reliable data to determine credible event probabilities, exemplified by the use of probability-of-exceedance (POE) to address external corrosion post-Inspection and Leakage Identification (ILI) Each identified anomaly, characterized by specific length and depth dimensions, informs the calculation of a safe operating pressure based on the pipe's properties The inherent uncertainty in tool accuracy enables the estimation of the likelihood that a detected anomaly will lead to a leak or failure at the MOP Consequently, operators must select a probability threshold to prioritize remediation efforts for anomalies with higher failure probabilities.

Characteristics of Risk Assessment Approaches

Pipeline operators must understand key characteristics of risk assessment methods to utilize them effectively These methods are fundamentally data-driven, relying on comprehensive system data, including pipeline attributes, construction and operational factors, and assessment histories, to evaluate threats to pipeline integrity Clearly defining critical locations is essential for understanding how a release from any segment can impact these areas Ultimately, the quality of the risk assessment hinges on both the data quality and the operator's expertise.

To accurately assess risk at a specific location, it is essential that the data used in the calculations is relevant and valid for that location Models employing dynamic segmentation continuously analyze pipeline data along the route, recalculating risk with each change in input variables In contrast, fixed segmentation models calculate risk based on a predetermined set of data for defined segments, where input values remain constant For dynamic segmentation, it is crucial to provide changing data points, while fixed segmentation requires users to establish segments with stable data.

Data weaknesses can cause risk scores to rely heavily on a single variable, raising concerns about their reliability For instance, if a model assesses the probability of external corrosion based solely on pipe-to-soil potential readings while assuming other factors like coating type, coating condition, soil type, and age remain constant, the risk assessment may be skewed Since these factors are unlikely to be uniform over long distances, operators should invest in understanding the variations in coating condition and soil type along the pipeline To ensure accurate risk calculations, operators must carefully evaluate both the data used and the resulting outputs against real-world experience.

To avoid failures in unassessed segments, operators should utilize relative risk scores to evaluate the outcomes of assessments, remediations, and mitigations from the highest-scoring segments Analyzing these initial segments helps gauge the reliability of the risk assessment Based on this analysis, operators can adjust the rates of integrity assessments and the implementation of preventive and mitigative measures as needed.

The scenario-based and probabilistic approaches to risk assessment provide risk values as probabilities of failure, requiring users to determine their acceptable level of risk over a specified timeframe For instance, a failure probability of \$10^{-6}\$ may imply that a segment can operate for \$X\$ years before requiring an integrity assessment, while a failure probability of \$10^{-3}\$ indicates that an integrity assessment is necessary within \$Y\$ years, where \$Y\$ is significantly shorter than \$X\$.

Risk assessment is a dynamic process that provides a framework for initiating integrity assessment programs, rather than guaranteeing absolute certainty in scheduling these assessments It should evolve with experience, serving as a continual planning tool for integrity evaluations Additionally, risk assessment must consistently identify preventive and mitigative measures for operators to consider As integrity assessments and remediation actions are executed, the operator's risk assessment model can be validated and refined based on the insights gained An adaptable risk assessment model is crucial for future planning of integrity assessments and actions, ensuring the ongoing integrity of the system.

To ensure the reliability of an operator's risk assessment process, it is essential to incorporate insights gained from integrity assessments and mitigative actions back into the risk assessment framework Key data to be collected for future integration and to inform the reassessment of risks, which may require adjustments to the risk assessment methodology, include the outcomes of these evaluations.

— number of repairs required during the previous inspection, testing and mitigative activity;

— type of defects found and their significance to pipeline integrity;

— different assessment technologies and improvements in technology used;

— changes in pipeline attributes and pipeline operations;

— alignment of findings from inspections and tests with what the model predicted;

— results of preventive and mitigative actions.

General

This section of the RP provides guidance on integrity assessment methods and repair methods and includes the following topics:

— appropriate ILI techniques for the various pipeline integrity threats,

— schedules for dealing with anomalies found by ILI,

— benefits and limitations of hydrostatic testing,

— various types of other technologies for finding anomalies,

— seam integrity assessment for lap-welded (LW) and ERW pipe,

— various types of repair methods that can be used to restore the serviceability of pipe affected by defects.

To reiterate what was explained in Section 4, the threats for hazardous liquid pipelines that operators should address can be characterized as follows: