This paper evaluates field ovalization measurements of NPS 24 pipe using 3D continuum finite element analyses. The combination of the soil backfill weight and loose bedding material beneath the pipe near a tie-in concentrates stresses at the location where native undisturbed soil transitions to loose backfill along the trench bottom, which increases the ovality in the pipe cross section. The analysis indicated that at burial depth, transient surface loading temporarily increases the ovality in unpressurized pipe but the ovality is reduced to near normal levels when the transient surface loading is removed. The internal pressure reduces the elastic pipe ovality. This analysis method can be useful for a cost benefit analysis between using thicker pipe, versus the additional costs, such as intervention and/or padding/compacting of soil around the pipe (with inspections).

In South America, there is not a unique standard that regulates the Design, Operation, Maintenance and Integrity Management of Pipelines. Most of the countries had developed their own regulations and standards based mainly on the ASME Standards. These standards (like ASME B31.8 and ASME B31.8S) are being developed and updated considering the experience of different operators, but the results not always consider the difficulties in terms of social and cultural aspects of construct and operate pipelines in South America. Expansion of existing residential and commercial areas, or the construction of new developments near these pipelines can change a Location Class 1 into a Class 2 or Class 3 location. This development is not always predictable, besides the efforts of the South American Pipelines Operators made to coordinate this expansions with the local authorities, the growth in these countries are not well planned and the Operators are forced to face the situation without anticipation and without a backup of the regulations. Then the operators are unexpectedly left with a pipeline that no longer meets the requirements of its design code. ASME B31.8 establishes alternatives to adequate this changes into the design code: reducing the maximum allowable operating pressure of a pipeline, pipeline replacement increasing the wall thickness or by re-routing it away from the population. Those alternatives have high costs and significant operational difficulties, especially when the social conditions are not favorable. Additionally, some of these options do not even effectively solve the problem. Lowering operating stress levels do not always address the higher risk levels or safety concerns caused by the change in class. Increasing wall thickness, can lower probability of failure for a pipeline but not for all the combinations of threats, which depend on site specific conditions. The Pipeline Integrity Management System shall address all the threats as it is specified in ASME B31.8S, ensuring human safety as its primary objective. Third Party Damage is an important threat which in most of the pipelines around the world has caused the larger number of incidents. To manage this threat, risk assessments have been employed successfully to determine risk based on land use zones, proximity to utilities, alignment markers, one call and dig notification, surveillance intervals, among other variables. Calculating the risk to a specific pipeline near to a population after the mitigation activities are implemented, it may be shown that this pipeline has no more risk than other pipelines operating entirely in accordance with the design codes. Risks must be maintained “as low as reasonably practicable”, using cost benefit analysis to achieve these criteria. The reduction of the risk is accomplished by implementing additional mitigation plans, allowing to effectively use maintenance resources in areas where they will have the highest impact on risk. This paper shows how risk and engineering assessments and their consequent mitigation plans may be used to justify the safe operation of a pipeline without changing its original operating pressure following a change of class designation, exemplified with a case study from South America.

Annually or as events occur, operators submit data to various regulatory agencies about the operation, maintenance and extent of their assets. Many of these figures are used by the public, non-profit organizations and private companies to independently conduct assessments about operators, ranging from safety to quality assurance to scope and nature of product deliveries. The Pipeline Hazardous Materials Safety Administration (PHMSA), the National Energy Board (NEB), and other industry organizations have recently put an emphasis on more meaningful metrics by releasing guidelines and leading discussions at industry conferences and workshops. In order to derive more strategic accuracy and pertinence, Explorer Pipeline Company (Explorer) and Det Norske Veritas (U.S.A.), Inc. (DNV GL) have developed a procedural effort to develop meaningful metrics. Several derivative benefits come from this effort such as support for calculating cost-benefit / ROI figures for maintenance projects, justification for compliance-plus activities and, most importantly, a more informed perspective of operational risk. A renewed approach to this effort is to organize the more meaningful factors into three categories: (1) Metrics of job roles and tasks within Explorer’s Asset Integrity staff, (2) Other existing influential metrics (3) Regulatory metrics. Using this approach, Explorer defined well-targeted, unitized metrics, each with a meaningful basis. Explorer anticipates the development of these more meaningful metrics to support the transparency sought by regulators and other stakeholders, benchmark and continually evaluate our Asset Integrity program and possibly support the development of practical metrics for the pipeline industry.

A reliability evaluation methodology, referred to as Sustainable Capacity, has been developed to quantify reliability expectations and provide a basis for the explicit consideration of reliability in pipeline design. The methodology, which has been adapted from one widely used in the electric power industry, is based on the representation of the load and capacity processes, which define reliability, with Markov models. These models generate time-series of simultaneous load and capacity profiles which are evaluated to determine reliability expectations. A cost-benefit methodology which recognizes the variation in the value attributed to pipeline reliability by individual customers is then used to assess the economic efficiency of any proposed facility addition. Further to its application as a design tool, the Sustainable Capacity methodology can also provide support in other areas such as operations and maintenance planning.

Pipeline projects impact the environment through soil and habitat disturbance, noise during construction and compressor operation, river crossing disturbance and the risk of rupture. Assigning monetary value to these negative project consequences enables the environment to be represented in the project cost-benefit analysis. This paper presents the mechanics and implications of two environmental valuation techniques: (1) the contingent valuation method and (2) the stated preference method. The use of environmental value at the project economic-evaluation stage is explained. A summary of research done on relevant environmental attribute valuation is presented and discussed. Recommendations for further research in the field are made.

This paper summarizes the fundamental aspects of the development of the Risk Assessment and Management (RAM) approach to define factors of safety for design and reassessment of pipelines and risers in the Bay of Campeche, Mexico. Based on a cost-benefit analysis associated to a particular development and generic type of system, as well as legal regulatory to national requirements, the target reliabilities for the system are defined. These target reliabilities are addressed in four quality attributes of the system: serviceability, safety, durability, and compatibility. The variabilities, uncertainties, and biases associated to the demands and capacities of the pipeline for the design and reassessment criteria are evaluated, and the factors of safety or allowable stress factors for single and combined in-place loadings are determined. The traditional Working Stress Design (WSD) format for guidelines is used here. This format utilizes a nominal “static” loading to define the serviceability response characteristics and strength of the structure.

To the end of 2012, Enbridge Pipelines employed an in-house developed indexed or relative risk assessment algorithm to model its liquid pipeline system. Using this model, Enbridge was able to identify risk control or treatment projects (e.g. valve placement) that could mitigate identified high risk areas. A changing understanding of the threats faced by a liquid pipeline system and their consequences meant that the model changed year over year making it difficult to demonstrate risk reduction accomplished on an annual basis using a relative scoring system. As the development of risk management evolved within the company, the expectations on the model also evolved and significantly increased. For example, questions were being asked such as “what risk is acceptable and what risk is not acceptable?”, “what is the true risk of failure for a given pipe section that considers the likelihood of all threats applicable to the pipeline”, and “is enough being done to reduce these risks to acceptable levels?” To this end, starting in 2012 and continuing through to the end of 2013, Enbridge Pipelines developed a quantitative mainline risk assessment model. This tool quantifies both threat likelihood and consequence and offers advantages over the indexed risk assessment model in the following areas: • Models likely worst case (P90) rupture scenarios • Enables independent evaluation of threats and consequences in order to understand the drivers • Produces risk assessment results in uniform units for all consequence criteria and in terms of frequencies of failure for likelihood • Aggregates likelihood and consequence at varying levels of granularity • Uses the risk appetite of the organization and its quantification allows for the setting of defined high, medium, and low risk targets • Quantifies the amount of risk in dollars/year facilitating cost-benefit analyses of mitigation efforts and risk reduction activities • Grounds risk assessment results on changes in product volume-out and receptor sensitivity • Balances between complexity and utility by using enough information and data granularity to capture all factors that have a meaningful impact on risk Development and implementation of the quantitative mainline risk assessment tool has had a number of challenges and hurdles. This paper provides an overview of the approach used by Enbridge to develop its quantitative mainline risk assessment model and examines the challenges, learnings and successes that have been achieved in its implementation.

The Compression Stations constructions were finished between 2009 and 2011 by PETROBRAS Engineering Department. TRANSPETRO had taken part in the whole design process, and is now responsible for the operation and maintenance of these stations, which were delivered with some items pending categorized as improvements. The principle objective of this study is to choose and adapt a method, based on portfolio management methodology, to undertake a portfolio of Natural-Gas Compression-Station projects with decision making supported by standardized criteria and developed scenarios, so that the needs of the company are satisfied with a good cost/benefit relationship. The Analytic Hierarchy Process was the method chosen for prioritization and selection of projects to be undertaken from the portfolio. The necessity to adapt this method to insert new projects throughout the year into the current portfolio was identified in order to attend the operational and maintenance demands.

As population growth and development occurs along the pipeline right of way, the class location of pipeline segments could change to a higher class designation. A higher location class designation has a more stringent location factor according to Canadian Standard Association (CSA) Z662-11 Clause 4.3.7. For this situation, Onshore Pipeline Regulations (OPR) s.42 requires pipeline operators to submit a proposed plan in conformance with CSA Z662 requirements in Clause 10.7. Typically for compliance, a change to higher class designation leads to pipe replacement or operating pressure reduction (compliance options). Alternatively, the pipeline segment could also be subjected to an engineering assessment (EA) to develop other measures which are as safe as or safer than the compliance options. The CSA code requirements of pipeline replacement or pressure reduction for out-of-class pipe cater to generic cases, and essentially make the out-of-class pipe segment comply such that it is within class. In contrast, a site-specific EA considers the actual pipe conditions, the relevant hazards, and the case specific solutions. Therefore, the site-specific EA provides a more appropriate solution for the problem at hand and ensures a risk consistent approach for the class change site. This also provides a safety level that is equivalent or above the regulatory requirements. A three-level engineering assessment methodology was developed for an out-of-class EA. In the first level assessment, the design, construction, testing procedures and the location class development are reviewed to understand the regulatory constraints and compliance aspects. In the second level assessment, all the potential hazards are identified and assessed to determine the pipeline condition. Finally, in the third level assessment, quantitative reliability assessment techniques were utilized to determine the optimized mitigation activities that can make the pipe segments as safe as or safer than the compliant options. The class change EA used the above methodology to quantitatively compare mitigation activities with pipe replacement and reduced operating pressure scenarios. Some mitigation activities provided greater safety than pipe replacement and reduced operating pressure scenarios, thus providing safer options while avoiding pipeline service interruption; minimizing in-field disturbances and related risks of replacement; and providing cost-benefit optimization. The growth of urban areas and related encroachment on pipeline corridors is a common occurrence. Therefore this EA approach has industry wide applications in providing safer and more optimized solutions.

Pipelines in remote and ecologically sensitive regions pose special challenges for pipeline integrity monitoring. These challenges include difficulties of access, reliability issues of communication and instrumentation that may impact the leak detection technology applied in these regions. The selection, application and continuous testing of an appropriate technology to detect possible leaks are important to pipeline integrity monitoring. The paper reports theoretical assessment and extensive testing on an Enbridge subarctic liquid pipeline. It also reports the comprehensive cost-benefit analysis to guide the leak detection instrument design/configuration and the evaluation of the capabilities of alternative computational pipeline monitoring (CPM) technologies for leak detection. The selected test pipeline is an 869 kilometer (540 mile), NPS 12 inch pipeline that transports sweet crude through environmentally sensitive areas. This pipeline currently uses a real-time transient model (RTTM) style CPM as the leak detection system (LDS). The pipeline LDS is tested annually by a number of industry-recognized methodologies. These include fluid withdrawal tests, simulated leak tests and an API-1130 instrument adjustment approach. This pipeline is also assessed by API-1149 for its theoretical CPM leak detection sensitivity. A pilot project invited commercial CPM-style vendors to participate in an LDS test using data from fluid withdrawal and simulated leak tests. Five vendors responded and were included in the test suite. The paper describes the design and implementation of the test process. The results of the commercial systems are presented in aggregated form and the participating vendors remain anonymous. Performance assessment focuses on the LDS evaluation factors of sensitivity and accuracy. The paper concludes with a “lessons learned” review of issues associated with test design.

OCP Ecuador S.A. was designed for transporting heavy crude oil from the Ecuadorian Amazonian forest to the Pacific Ocean, crossing the Andes (highest point @ 4060 masl). OCP have four pumping stations PS1, PS2, PS3, PS4 located across the first 182km. Main pumps were designed with an inherent product circulation from pressure connection via orifice to mechanical seal (API Plan 11) for lubricating and cooling. In order to achieve required viscosity, crude oil from the main line must be heated. Low sulfur crude oil (LSCO) is burned for this purpose. In order to optimize fuel consumption, some efforts were conducted since 2006. The first aim was to increase feed rate of lubricating oil, in order to extend the viscosity within seals up to 700cP. This modification resulted in considerable heat exchange depletion, representing about 50% of costs reduction related to reduce heating of crude oil in the main line. Since 2009, there were some adverse scenarios, which forced the company to seek more and better ways to optimize the fuel oil consumption. These scenarios were: • The continued decline in the quality of crude oil delivered by the shippers quality from shippers. Reduced quality was seen as a threat to the integrity of mechanical seals. • Unavailability of LSCO in the country, • The under-utilization of transport capacity due to low volumes of oil (30% of its capacity). Facing this situation, OCP decided to analyze the technical and economic feasibility of operating without heating oil, in an intermediate pump station (PS3: KP 148 @ 1800 masl). This pump station, at the time of the study, was operated heating crude oil. The greatest difficulty in achieving the goal of reducing heating oil was the maximum viscosity that mechanical seals could withstand, without affecting its integrity. To mitigate this threat, an API plan 32 was designed and implemented in PS3. Simultaneously, the organization was evaluating the possibility of installing a similar system in PS4, where climatic conditions are more adverse than PS3. Based on thermal models and after risk evaluation and cost benefit analysis, OCP decided to run operations accepting the risk of potential damage to the seals in PS4. At the moment, OCP Ecuador S.A. is operated without heating crude oil and API plan 32 was placed on standby, reducing considerably the operating costs. This paper is intended to share the learned lessons, some actions taken; obstacles faced up as well as achieved results in this cost reduction effort.

Expansion of existing residential and commercial areas, or the construction of new developments in the vicinity of high pressure gas transmission pipelines can change a Location Class 1 into a Class 2 or Class 3 location. Operators are left with a pipeline that no longer meets the requirements of its design code. Reducing the maximum allowable operating pressure of a pipeline, or re-routing it away from the population, can meet the requirements of a design code, such as CSA Z662 or ASME B31.8, but such options have both high costs and significant operational difficulties. Quantitative risk assessment has been employed successfully for many years, by pipeline operators, to determine risk based land use planning zones, or to justify code infringements caused by new developments. By calculating the risk to a specific population from a pipeline, and comparing it with suitable acceptability criteria, a pipeline may be shown to contribute no more risk to a population than other pipelines operating entirely in accordance with the design codes. Risks may be demonstrated to be ‘as low as reasonably practicable’, through the use of cost benefit analysis, without additional mitigation, allowing precious pipeline maintenance funds to be spent most effectively in areas where they will have the highest impact on risk. This paper shows how quantitative risk assessment may be used to justify continued safe operation of a pipeline at its original operating stress following a change of class designation, illustrated with a case study from Western Europe.

To aid with making risk-based pipeline management decisions, a methodology is required to evaluate the cost-benefit of various pipeline operation strategies as a function of time. This methodology should provide consideration to evaluating an existing asset with active damage mechanisms and imperfections in various states of severity. In this paper, the subject of the methodology is a typical transmission pipeline with the following properties: • Transports refined liquid products; • Mid-size diameter (NPS 8 to NPS 16); • Telescoping wall thickness based on proximity to pump stations (4 to 6 mm); • High pressure (9930 kPa); • Approximately 50 years of operating history; and • Approximately 500 km long. The objective of this analysis is to determine the best operation strategy for the subject pipeline in terms of cost-effective risk management. The methodology considered four different risk management strategies: • Operate and Maintain (O&M) at 100% of Maximum Operating Pressure (MOP): ○ A maintenance strategy involving in-line inspection and defect repair based on a function of probability and consequence of failure while operating at 100% of MOP. • Operate and Maintain (O&M) at 50% of Maximum Operating Pressure (MOP): ○ Similar to the previous strategy except an additional form of mitigation is applied by reducing the operating pressure of the pipeline to 50% of MOP. • Inspect, Repair and Re-coat (IRR): ○ A maintenance strategy involving complete excavation of the entire pipeline, inspection and repair of any defects, re-coat and burial. • Pipeline Replacement: ○ A maintenance strategy where the existing asset is abandoned and replaced with a new pipeline. To complete the analysis, two predictive models to determine probability of failure (POF) and consequence of failure (COF) were created using quantitative and semi-quantitative approaches. Consideration was given to both time dependent imperfections and time independent damage mechanisms. The effects of each risk management strategy were projected in both models over a timeline of 20 years. The results were aligned to a risk matrix with defined risk thresholds to aid in determining the acceptability of each risk management strategy. To evaluate the effectiveness of each risk management strategy, a cost-benefit ratio was used. This ratio was defined as the predicted risk reduction through the implementation of each strategy over the costs required for execution. Maximizing this ratio would represent the optimal strategy at any given point in time. Completing the analysis showed that over the short term the O&M strategy was the most cost-effective methodology to mitigate risk. However, as a pipeline ages and repairs become more frequent, the replacement strategy becomes more favorable. The analysis predicted a time interval where if the subject pipeline is to be operated beyond this point in time then replacement as soon as possible is the best strategy to employ. This time interval is different between pipelines and heavily dependent on the rate and severity of damage. The results in this paper illustrate an example and utilizing the methodology discussed will produce different results on a case-by-case basis.

The purpose of this paper is to present the study concerning the evaluation of the repair logistics of gas pipeline Urucu-Coari-Manaus (extension of 600 km), that was constructed to operate in the Amazon Brazilian region. Repair logistics is a challenge, regarding specific operation conditions in the jungle, environment and flood variations, difficulty on accessing pipeline right-of-way, difficulty on transportation, etc. Workshops were held, gathering most experienced company personnel from different PETROBRAS sectors (engineering, operation, repair centre, integrity area, Brazilian Army, offshore sector, etc.), in order to evaluate and establish strategies for each identified failure scenario, considering type of repair, logistics, resources and costs. The first step of the study was to incorporate the experience obtained from the engineering team, responsible for the construction of Urucu-Coari-Manaus gas pipeline as they had to face unexpected and adverse conditions. Based on their experience, different pipeline sections were defined, considering specific features, like isolation, flooded areas, river crossings, access limitations, etc. The second step was brain-storming workshops with the purpose of providing the best PETROBRAS evaluation of pipeline sections repair strategies, logistics and resources. Failure frequencies were raised and addressed, as well as variables like: - time for failure detection, for digging, for repair, for resources arrival, considering different logistics and transportation modes (using specific boats, helicopters with special characteristics, such as suitable for long line operations (load line greater than one rotor diameter in length), capable of transporting heavy equipment, etc.). Innovative ways of repair were conceived and proposed to be used. Supply contract conditions for thermo plants, industrial and residential consumers were considered. Finally, a cost/benefit analysis was performed, considering expenses on logistics and resources and benefits associated with avoided losses for each specific failure scenario, in order to provide support for decision making process.

The purpose of this paper is to present the innovative reliability modeling of Petrobras 2010 integrated gas supply chain. The model represents a challenge in terms of complexity and software robustness. It was jointly developed by PETROBRAS Gas & Power Department and Det Norske Veritas. It was carried out with the objective of evaluating security of supply of 2010 gas network design that was conceived to connect Brazilian Northeast and Southeast regions. To provide best in class analysis, state of the art software was used to quantify the availability and the efficiency of the overall network and its individual components (such as gas processing units, city-gates, compressor stations, pipelines). The study requests, as input, a lot of information, that should be provided from different sectors of Petrobras, since it is supposed to depict reliability performance of all gas supply chain players. Information such as 2010 design configurations, gas offer and demand profiles, shedding priority, pressure delivery conditions, supply contract and associated penalties, commodity prices, etc., should be raised and addressed. More than twelve processing plants were modeled, in a detailed manner, and have their performance indicators compared. Different gas sources were considered in the study, such as offshore platforms, onshore fields, Bolivia pipeline and LNG ships. Detailed failure probability and repair data were addressed. Contingency plans, for each identified scenario, were made, in order to evaluate probable losses that constitute an input for the reliability modeling. Therefore, two additional software’s were used for their validation: - Pipeline studio – TGNET (from Energy Solutions), to check pressure conditions; and an in-house Petrobras software (PLANAGE), used for best gas allocation purposes. Experienced operational team opinion was incorporated on that contingency plans elaboration. This work constitutes a powerful tool for Petrobras planning and optimization of gas supply chain future configurations. The simulation provides propositions for investments prioritization, based on cost benefit analysis, and as a by-product, contingency plans, that were developed, considering different failure scenarios.

With the availability of in-line inspection data, pipeline operators have additional information to develop the technical and economic justification for integrity verification programs (i.e. Fitness-for-Purpose) across an entire pipeline system. The Probability of Exceedance (POE) methodology described herein provides a defensible decision making process for addressing immediate corrosion threats identified through metal loss in-line inspection (ILI) and the use of sub-critical in-line inspection data to develop a long term integrity management program. In addition, this paper describes the process used to develop a Corrosion In-line Inspection POE-based Assessment for one of the systems operated by TransGas Limited (Saskatchewan, Canada). In 2001, TransGas Limited and CC Technologies undertook an integrity verification program of the Loomis to Herbert gas pipeline system to develop an appropriate scope and schedule maintenance activities along this pipeline system. This methodology customizes Probability of Exceedance (POE) results with a deterministic corrosion growth model to determine pipeline specific excavation/repair and re-inspection interval alternatives. Consequently, feature repairs can be scheduled based on severity, operational and financial conditions while maintaining safety as first priority. The merging of deterministic and probabilistic models identified the Loomis to Herbert pipeline system’s worst predicted metal loss depth and the lowest safety factor per each repair/reinspection interval alternative, which when combined with the cost/benefit analysis provided a simplified and safe decision-making process.

This paper presents a case study, which is currently being carried out on a high-pressure sub-sea gas export pipeline. The main objective of the case study is to determine if the risk mitigation measures that are already in place are sufficient considering the level of risk for different sections of the pipeline. The methodology utilizes a Geographical Information System and the COmputer Assisted Shipping Traffic (COAST) database to determine the level of risk caused by vessels traveling over the pipeline. The factors considered are damaged due to anchor drop and drag, vessel foundering and grounding over the pipeline. Live vessel tracks obtained from nearby radar stations are used to determine the annual traffic volume, size, type and speed of vessels as well as vessel headings. This information is then fed into the COAST database and presented graphically. The pipeline is then divided into equal area cells and the probability of anchor dropping and dragging and vessel foundering and grounding are calculated based on the type, size and speed of the vessels identified to have passed over the pipeline. The results of the frequency of occurrences and fatalities are presented and then evaluated against the set As Low As Reasonable Practicable (ALARP) level. The “hot spots” of the pipeline are identified and a base case study is carried out for the risk reduction measures that are in place (if any) for each of the “hot spots” identified. Alternative risk reduction measures are considered and a cost benefit analysis is carried out to determine the most feasible option. The risk levels are then recalculated with the risk reduction measures in place to see if this has reduced the risk to ALARP. The COAST database is thought to be very useful as it can be updated to reflect the current navigational practices of vessels and hence, it would be easy to update analyses as and when required.

The pipeline industry has implemented a process for acquiring data and information necessary to support technically-based standards and regulations through techical studies and research and development (R&D). This process enabled the development of ASME B31.8S based on the technical facts gathered, drawing upon all stakeholders including Federal and State regulators, pipeline operators, manufacturers and suppliers and members of the public. This paper describes the process being used by the gas pipeline industry to develop standards such as B31.8S and provides examples of the benefits derived from standards. It examines in detail the benefits that the pipeline industry and regulators derived from the timely development of ASME B31.8S - Integrity Management of Gas Pipelines and the process used to support the standards’ development. The Office of Pipeline Safety developed a cost/benefit analysis to support the final rule on Integrity Management in High Consequence Areas. The OPS analysis indicates that the net cost for the gas pipeline industry to implement this program is now $4.7 B over the next 20 years as compared with the proposed rule based on the Pipeline Safety Improvement Act of 2002 which they estimated to cost $10.9B over the same period. OPS has incorporated B31.8S into its regulations, which has significantly simplified them, yet through prescriptive requirements, has provided an equal or better level of safety as envisioned by Congress. While the timely development played a major role in the distillation of the regulations, B31.8S cannot take credit for the full $6.2B savings to the industry. The estimated savings provided by B31.8S to the industry will be described. Industry management and the regulators are encouraged to fully support the continuing development of standards for the pipeline industry utilizing the model developed by the gas pipeline industry.

Industry standards (i.e. API 1160, ASME B31.4 and B31.8S-2001, CSA-Z662-2003) and regulations (i.e. US DOT 49 Parts 195-2002 and 192-2003, and NEB On-shore 99) have delineated the risk-based elements of oil and gas pipeline integrity management programs. A Fitness-For-Service Assessment is part of an overall Integrity Management Program that is implemented for the pipeline system depending on the required pipeline operational conditions, severity of integrity threats, and their impact or consequences to the public, environment and employees. This paper provides guidelines for pipeline operators of oil pipeline systems exposed to corrosive and geotechnical sensitive environments and high consequence areas to develop long term integrity plans. In this case, the pipeline integrity plans were prepared based on the integration of data and assessments such as metal loss, geometry and strain in-line inspections, product corrositivity, cathodic protection, geotechnical hazard identification, and pipe class location/high consequence areas. Guidelines for developing near-term integrity plans are herein provided based on best industry practices and regulations. In 2002, Oleoducto Central S.A. (Ocensa) and CC Technologies initiated the Phase 1 of the Fitness-for-Service assessment of 698 km of NPS 16/30 crude oil pipeline from Cupiagua to Coven˜as. Phase 1 was comprised of an internal corrosion study to assess the corrosivity of the product and its impact in the future. Corrosivity of the crude oil was determined from laboratory testing and correlated to the pipeline operational and topographical conditions. In 2003, the Phase 2 of the Fitness-for-Service assessment was comprised of a review of the near-term maintenance program and the development of the long-term maintenance program. The long-term integrity plan program for corrosion features was developed using a deterministic and probabilistic corrosion growth modeling to determine excavation/repair and re-inspection interval alternatives. The corrosion growth modeling took into account the in-line inspection tool accuracy based on the field validation program. The most cost effective alternative was identified by using a cost benefit analysis technique. This implemented approach contributed to timely schedule maintenance activities. In addition, the selected excavations confirmed with high confidence the results from the Ocensa-CC Technologies Canada predictability model. Geometry features reported by the geometry/inertial in-line inspection were initially evaluated, and correlated to the corrosion in-line inspection data, and the geotechnical hazard study to identify potential locations of slope instability, river-crossing scouring for assessing internal corrosion criticality. Strain areas were also assessed and correlated to pipe wall deformation and potential areas of land movement. Pipe class location limits were determined based on latest dwelling locations and distribution, and then correlated to the reported corrosion features for verifying minimum safety factors. The long-term maintenance program was integrated from all assessments performed on the identified integrity threats. As a result, guidelines were prepared for implementing technically sound and economically-optimized long-term inline inspection, excavation and repair plans.

Implementation of Integrity Management Programs (IMP) for pipelines has motivated the design of Fitness-For-Service methodologies to assess Stress Corrosion Cracking (SCC) and fatigue-dependent features reported by Ultrasonic Crack Detection (UTCD) In-Line Inspections. The philosophical approach defined by the API 579 [1] “Fitness-For-Service” from the petrochemical industry in conjunction with Risk-based standards and regulations (i.e. CSA-Z662-2003 [2] and US DOT 49 Parts 192 [3] and 195 [4]) and in-line inspection validation (i.e. API 1163 [5]) approaches from the pipeline industry have provided the engineering basis for ensuring the safety, reliability and continued service of the in-line inspected pipelines. This paper provides a methodology to develop short and long-term excavation and re-inspection programs through a four (4) phase-process: Pre-Assessment, Integrity Criticality Assessment, Remediation and Repair, Remaining Life Extension and In-Service Monitoring. In the first phase, Pre-assessment, areas susceptible to Stress Corrosion Cracking (SCC) and fatigue-dependent features are correlated to in-line inspection data, soil modeling, pipeline and operating conditions, and associated consequences in order to provide a risk-based prioritization of pipeline segments and technical understanding for performing the assessment. The second phase, Integrity Criticality Assessment, will develop a short-term maintenance program based on the remaining strength of the in-line inspection reported features previously correlated, overlaid and risk-ranked. In addition, sites may be identified in Phase 1 for further investigation. In the third phase, a Remediation and Repair program will undertake the field investigation in order to repair and mitigate the potential threats as well as validating the in-line inspection results and characterization made during the Pre-assessment and Integrity Criticality Assessment (Phases 1 & 2). With the acquired knowledge from the previous three (3) phases, a Remaining Life Extension and In-Service Monitoring program will be developed to outline the long-term excavation and re-inspection program through the use of SCC and Fatigue crack growth probabilistic modeling and cost benefit analysis. The support of multiple Canadian and US pipeline operating companies in the development, validation and implementation of this methodology made this contribution possible.