All buried pipes experience loading from the weight of soil overburden. When pipelines cross railroads, roads, parking lots or construction sites, the pipes also experience live surface loading from vehicles on the ground, including heavy construction equipment in some scenarios. The surface loading results in through-wall bending in pipes, which generates both hoop stress and longitudinal stress. Current standards limit the stresses in buried pipes to maximum values in terms of hoop stress, longitudinal stress and combined biaxial stress. An early approach to estimating stresses and deformations in a pipe subjected to surface loads dates back to Spangler’s work in the 1940s. Many models have been developed since then. API RP 1102 provides guidance for the design of pipeline crossings of railroads and highways following the model developed by Cornell University for the Gas Research Institute (GRI). The Cornell model was developed only based on experiments on bored pipes crossing a railroad or a highway at a near-right angle. The live surface loading distribution is also limited to the wheel-layout typical of railroad cars and highway vehicles. Most other existing models only focus on the hoop stress in the pipe. In this paper, a new approach to determine the stresses in buried pipes under surface loading is introduced. The approach is suitable for assessing pipes beneath any type of vehicle or equipment at any relative position and at any angle to the pipe. First, the pressure on the pipe from surface loading is determined through the Boussinesq theory. Second, both hoop stress and longitudinal stress in the pipe are estimated. The hoop stress is estimated through the modified Spangler stress formula proposed by Warman and his co-workers (2006 and 2009). The longitudinal stress, due to local bending and global bending, is estimated by the theory of beam-on-elastic-foundation. The modulus of foundation can be determined through the soil-spring model developed by ASCE. The hoop stress, longitudinal stress and the resulting combined biaxial stress can then be compared against their respective limits from a pertinent standard to assess the integrity of the pipe and determine the proper remediation approach, if necessary. The performance of the proposed approach is compared in this study with the experimental results in the literature and the predictions from API RP 1102.

Pacific Gas & Electric Company (PG&E) operates multiple gas transmission pipelines on the San Francisco Peninsula, a significant portion of which operate at low Maximum Allowable Operating Pressure (MAOP), typically below 300 psig and are challenging to inspect using traditional ILI technology. This paper describes PG&E’s use of Non-Traditional robotic ILI technology to inspect numerous cased pipelines located in High Consequence Areas in the highly populated and dense urban area between the San Francisco International Airport (SFO) and central San Francisco. Examples will be provided for pipeline segments installed in various casing types, including sections inserted through utility infrastructure that was made available for use as a gas pipeline casing. Examples include pipe that was installed in the 1940’s and cased pipe installed without corrosion test stations. In some instances, the length of cased pipe sections were several hundred feet long and traversed locations difficult to access, such as major highway crossings and cased spans above water crossings. These inspections were executed in 2015 on 24 separate pipeline segments totaling more than 12,000 feet of pipeline. This paper explains how the inspection team utilized current technology and identified Non-Traditional ILI (NT ILI) as the preferred method. It also explains how the locations were scoped, project parameters and program strategy were developed, NT ILI tool selection, project outcomes, and lessons learned. An overview of the advantages of NT ILI methods to perform these cased pipeline inspections in-lieu of External Corrosion Direct Assessment (ECDA) and Traditional ILI will be discussed. This paper is applicable to Track 3 (Pipelines & Facilities Integrity) and also to Track 2 (Project Management, Design, Construction & Environmental Issues), and will be of interest to Pipeline Operators, Integrity Management Engineers, and Project Managers. The intent is to share PG&E’s experience utilizing Non-Traditional robotic ILI tools to perform difficult pipeline inspections in casings, as well as practical advice on scoping, planning, and execution of non-traditional ILI projects.

This paper discusses the benefit of using single-tap double block and bleed (DBB) technology to isolate large diameter (24-inch and 36-inch) natural gas transmission lines during tie-in of a pig launcher and receiver in Surrey, British Columbia, Canada. The pipeline, which is owned by FortisBC, is the only source of supply for the city of Coquitlam, the Vancouver Island system, and a major power generation facility. As such, shutting down the line was not an option. Instead, the project required a bypass. However, the footprint of the jobsite was too small for a traditional bypass. In addition, the jobsite’s location adjacent to a major highway and a tight timeline meant that first time isolation success was mandatory.

The majority of pipeline transportation facilities for natural gas, liquefied petroleum gas and basic petrochemical products were built in Mexico during the 60’ −70. The most recent construction occurred between the 80–90’s. These gas pipelines are located in 24 of the 32 Mexican States, crossing through private property, agricultural fields and sharing right of ways with other Pipeline Companies. The length is up than 11,000 km., beginning in Cactus, Chiapas and ending in Chihuahua. Import/export points are located in Reynosa, Laredo, Piedras Negras and Ciudad Juarez, crossing many populated areas, fresh and salty waters bodies, highways, bridges, areas of irregular topographical terrain. This situation makes operation, maintenance, safety and inspection activities difficult to realize. Therefore, Pemex Gas y Petroquimica Basica established a technical information system, to have integrated digitized pipeline trajectory, on several geographic maps, and technical databases associated related maintenance, operation and safety. Technical consultation is the main project goal, either in headquarters or “in situ” if it were necessary, to aid in decision-making processes, or to take right choices in case of any incident.

PETRONAS Gas Berhad (PGB), a listed partly-owned subsidiary of PETRONAS is undertaking the Peninsular Gas Utilization Project - Stage III (PGU III). The PGU III Sector 2 & 3 project extends from Lumut, Perak to Pauh, Perlis on the West Coast of Peninsular Malaysia, with two laterals, the Gurun Lateral and the Penang Lateral. The Penang Lateral is further divided into the Prai Lateral, Gelugor Mainline and the Gelugor Tenaga National Berhad (TNB) Meter Station project individually. This paper will focus its’ discussion on the technical and engineering challenges faced in the design of the Gelugor Mainline Project. The Gelugor Mainline consist of about 7 km NPS 24 gas pipeline which runs from TNB Prai Power Plant of the mainline to TNB Gelugor Power Plant on the Penang Island. The pipeline is planned to operate at high pressure. The pipeline route traverses complex terrain with varied seabed lithology with depth up to 16m. The pipeline will cross active shipping lane, zones of live electrical cables, extensive system of submarine pipeline, mudbank and areas susceptible to mass gravity flows. There is also an area subjected to future development with an expected 170 kN/m 2 distributed load with 3 m covers required which is an expressway and Light Rapid Transportation (LRT) system, the proposed development of a “Vision City” is also a few meters away from the pipeline. The pipeline also passes by an environmentally sensitive area that includes the rearing of caged fishing activities. It is essential for the project team to determine and investigate the variable risks to the pipeline in order to take appropriate evasive and mitigating action in design. This required comprehensive survey activities in the busy shipping straits. The paper will explore and detail out its’ study starting from the description of the design concept to the varied environmental challenges. This paper aims to describe the route selection process, the pipeline design process and outline some of the specialist techniques employed in the design construction of the Gelugor Mainline, Penang, Malaysia. In nearly every major project a drive for cost and risk reduction results in a number of new ideas with varying degree of impact. Hence, the following areas will be elaborated and presented in greater details: • Pipeline Design. • Pipe-lay vessel. • Pipeline installation methodology.

This paper describes R&D efforts and trends and possible application of new technologies to improve on pipeline construction and operations. The paper also identifies possible solutions for some operating concerns related to pipeline integrity and safety. Safety is defined as protection for humans, the environment and materials/equipment. As in other industries, the oil & gas business too is driven by events; a typical example is the current interest on Stress Corrosion Cracking (SCC). Accordingly, there are technical concerns related to the influence of SCC and aging on pipeline integrity and the consequent financial concerns regarding possible pipeline upgrading, derating, abandonment and possible retrieval. Potential new solutions include a proposed flexible tube (currently under development) made out of fibre glass composites. This patented innovation could reduce pipeline construction and operating costs. This tube could also eliminate some problems typically associated with metal corrosion. Also included is the application of Fibre Optic Sensor (FOS) technology to the monitoring and evaluation of pipeline integrity. FOS technology may be utilized to study SCC because of its high resolution, and its insensitivity to electro-magnetic interference, and its real time availability. This cost effective technology is currently utilized in the monitoring and evaluation of a variety of structures such as airplanes, engines, generators, bridges and along highways. Optical fibres have the ability to detect a wide range of physical, mechanical, chemical and biological parameters, as: • frequency • temperature • pressure • strain-stress • residual-strain • vibration • damage • impact • displacement • deformation • acoustic-emission • wear • electric-fields • acceleration • rotation • voltage • chemical-species • refractive-index • chemical-reactions • load • liquidlevels • cracking If a fibre optic cable acting as a sensor can be applied to a pipeline system in a practical manner, it may be possible to monitor the performance and conditions of a pipeline over its operating life.

Oil and gas production in Canada’s west has led to the need for a significant increase in pipeline capacity to reach export markets. Current proposals from major oil and gas transportation companies include numerous large diameter pipelines across the Rocky Mountains to port locations on the coast of British Columbia (BC), Canada. The large scale of these projects and the rugged terrain they cross lead to numerous challenges not typically faced with conventional cross-country pipelines across the plains. The logistics and access challenges faced by these mountain pipeline projects require significant pre-planning and assessment, to determine the timing, cost, regulatory and environmental impacts. The logistics of pipeline construction projects mainly encompasses the transportation of pipe and pipeline materials, construction equipment and supplies, and personnel from point of manufacture or point of supply to the right-of-way (ROW) or construction area. These logistics movement revolve around the available types of access routes and seasonal constraints. Pipeline contractors and logistics companies have vast experience in moving this type of large equipment, however regulatory constraints and environmental restrictions in some locations will lead to significant pre-planning, permitting and additional time and cost for material movement. In addition, seasonal constraints limit available transportation windows. The types of access vary greatly in mountain pipeline projects. In BC, the majority of off-highway roads and bridges were originally constructed for the forestry industry, which transports logs downhill whereas the pipeline industry transports large equipment and pipeline materials in both directions and specifically hauls pipe uphill. The capacity, current state and location of these off-highway roads must be assessed very early in the process to determine viability and/or potential options for construction access. Regulatory requirements, environmental restrictions, season of use restrictions and road design must all be considered when examining the use of or upgrade of existing access roads and bridges. These same restrictions are even more critical to the construction of new access roads and bridges. The logistics and access challenges facing the construction of large diameter mountain pipelines in Western Canada can be managed with proper and timely planning. The cost of the logistics and access required for construction of these proposed pipeline projects will typically be greater than for traditional pipelines, but the key constraint is the considerable time requirement to construct the required new access and pre-position the appropriate material to meet the construction schedule. The entire project team, including design engineers, construction and logistics planners, and material suppliers must be involved in the planning stages to ensure a cohesive strategy and schedule. This paper will present the typical challenges faced in access and logistics for large diameter mountain pipelines, and a process for developing a comprehensive plan for their execution.

Sinkholes are common features in parts of Florida, and the Florida Geological Survey maintains an online database of sinkhole incident reports (SIRs) that was started in 1965. The incident reports are accepted “as-is” without verification; sinkhole location, length, width, and depth are included in SIRs. A desktop assessment of sinkhole activity in northern Florida was developed on the basis of SIRs that were available in GIS (shape file) format from the Florida Geological Survey website and an understanding that sinkhole activity needed to be normalized to length for use in pipeline risk assessments. The rate of sinkhole development in northern Florida was quantified by extracting sinkhole locations within 10 miles of a 230-mile-long hypothetical alignment of a pipeline and lateral. Over 500 sinkholes were located within the approximately 4,700-square mile polygon. Sinkhole trends aligned to highways indicate more complete reporting; therefore, 33 road segments comprising a combined length of about 944 miles within the polygon were used for statistical analysis. The SIR database was accepted as an accurate portrayal of sinkholes during its 47-year existence. Sinkhole activity was portrayed as annual frequency for sinkhole width or length ranging from 1 to 500 feet and normalized to 1 square mile and 1 lineal mile. A sinkhole 2 feet or larger in width occurs on average 8 times per year somewhere within 10 miles of the hypothetical alignment; whereas, a similar sinkhole occurs on average 4 times per year along a length of 944 miles. A 2-foot or larger sinkhole occurs on average about every 600 years within any 1 square mile of the 4,700-square-mile area and about every 200 years along any 1 mile of alignment length. On a per-lineal-mile basis, the expected 1,000-year sinkhole would be at least 9 feet wide; whereas the 1,000-year sinkhole would be at least 22 feet wide. Performance of specific pipelines under loading conditions associated with sinkholes of various widths can be assessed and used in a pipeline risk assessment.

One of the biggest challenges that Pipeline Operators face is the rehabilitation or replacement of long, old pipeline segments that have restrictive right-of-way access, such as those crossing a major waterway or highway or through an environmentally sensitive area where traditional dig and replacement is not an option. Typically, these projects have limited options and have high associated costs. Pipeline downtime is also a major factor in the project planning. Horizontal Directional Drilling and lengthy environmental impact studies are two examples of costly and/or time-consuming activities common to these projects. Self-monitoring, high-pressure internal replacement (HPIR class) composite pipeline systems are a viable alternative for replacing these hard to access pipelines, with little disruption to the pipeline right-of-way. HPIR class composite systems are installed into the old pipeline in very long lengths, negating the requirement for multiple excavations along the pipeline. Although inserted inside the old pipeline, they are not a simple plastic “liner”. They are fully structural, transporting high-pressure oil, gas and hazardous materials, with no dependence on the corroded steel pipeline. State and federal regulatory codes mandate the replacement of pipelines under certain conditions as part of the integrity management programs implemented as a result of the United States 2002 Pipeline Safety Act. However, these codes do not always consider the impact that traditional trenching and replacement has on public safety, nor on environmentally sensitive areas such as wetlands, national parks or endangered species habitats. This paper will address the following aspects of pipeline replacement, in hard-to-access areas, such as those that cross navigable waterways: 1) The traditional methods and limitations related to replacing the pipeline segments in hard-to-access areas 2) Composite technologies available today 3) Case study of replacement of regulated pipeline segments using HPIR class composite pipeline systems.

For more than half a century, cased crossings have been used to support oil and gas steel pipes for crossing highways, railways, or rivers. Leaks or ruptures of cased crossings have occurred that resulted in casualties and property damage. Unlike uncased pipes buried in soils, which can be assessed for external corrosion directly and indirectly, the presence of a steel casing wall makes it challenging, even if possible, to conduct these assessments. The effect of the casing wall on the external corrosion of the carrier pipe inside the annulus is not well understood; it is unclear what tools can be used to effectively inspect the cased pipes. Empirical experience from the pipeline industry has shown that a few tools can be used to detect the contact status between a casing and the carrier pipe, which can help assess the severity of the carrier pipe external corrosion. Unfortunately, the criteria used to detect a contact status vary by user for the same tool and thus, the effectiveness of these criteria is uncertain. This paper reports results from a recent study aimed at evaluating the effectiveness of AC current attenuation, AC voltage gradient, and close interval (potential) survey as tools for detecting the contact status between a casing and the carrier pipe.

Linear works, such as highways, power lines, gas and oil pipelines among others, as well as other types of engineering works can be threaten by natural hazards, such as landslides, floods, erosions, earthquakes, hurricanes, seaquakes and others, which may lead to great environmental impacts, very high sum of money lost and even deaths. Aiming to reduce geological and geotechnical risks, preventive or corrective actions can be executed from the design phase to the operational and maintenance stages in pipelines. In the last phase, an integrity management plan can be adopted to mitigate residual risks not covered on the design and construction phases. One of the alternatives to implement a gas pipeline integrity management is found in the code “Managing System Integrity of Gas Pipelines” – ASME B31.8S (2005). However, this code has some limitations in actions concerning to prevention, identification and correction of geological and geotechnical problems. This paper presents information about geotechnical risks in transmission pipelines and tools applied in identification, prevention and correction of geotechnical problems in pipelines, as well as, others that can potentially be applied in pipelines. A basic pipeline integrity management plan focused on geotechnical risks is proposed in the paper, transcribed as a contribution to ASME B31.8S Code. This plan is composed by actions: from identification, prevention, evaluation and analysis to correction of geotechnical instabilities in pipelines. It is composed by a flowchart with all actions selected for the geotechnical risk care. The plan was developed based on directions set in ASME B31.8S Code, including Brazilian, Italian and Canadian experiences.

The 2003 Kern River Pipeline Expansion will loop 635 miles of 36-inch high-pressure natural gas pipeline between southwest Wyoming and southern California and 82 miles of 42-inch pipeline in southern California. The Weber River near Coalville in Summit County, Utah, will be crossed using horizontal directional drilling (HDD) techniques. The original Kern River Pipeline was constructed across the Weber River using conventional open-cut methods in 1991, but environmental factors and the close proximity to other pipelines made HDD a reasonable option to consider. The Weber River floodplain is approximately 3500 feet wide at the pipeline crossing, and contains Interstate Highway 80, US Highway 189, and a paved frontage road. Geometry of the slopes above the floodplain results in an overall HDD horizontal length of 4750 feet with an elevation difference of 88 feet. The geologic setting of the Weber River crossing consists of Cretaceous marine and non-marine sedimentary rocks and Quaternary alluvial and colluvial deposits. The rocks are chiefly sandstone, siltstone, and claystone, with local limestone and coal. Sedimentary beds dip to the west at 10 to 30 degrees, and fractures dip at 60 to 80 degrees. The siltstone and claystone are soft to moderately soft, whereas the sandstone and limestone are moderately hard to hard. The alluvial deposits consist of silty sand to sandy gravel, and the colluvial deposits consist of silty clay to silty sand. A north-trending, west-dipping normal fault shown on published maps nearly coincides with Interstate 80. Geotechnical conditions at the proposed HDD crossing were evaluated by drilling six borings to depths ranging from 100 to 150 feet, and collecting ground penetrating radar (GPR) data at 11 profile lines covering 2170 feet of floodplain. The GPR profile lines were interrupted by channels of the Weber River, canals, and Interstate 80. A 25 MHz antenna was used to obtain radar penetration to effective depths of 50 feet or more. The contact between alluvial deposits and bedrock was detected at depths ranging from 20 to 50 feet. Local relief of the alluvial/bedrock contact was found to be on the order of 10 feet. DrillPath 2 and DrillMud programs were used for a preliminary evaluation of the HDD feasibility. A maximum HDD installation depth of approximately 105 feet was used, and fracture pressures were evaluated for a pilot hole and four stages of back-reaming. Locations of frac-out concern were identified. Final HDD design was performed by others.