bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reactivating a Legacy Pipeline: Simulating ILI Run Behavior, Operation Optimization, and Project Challenges
Authors: Bonner Dan , Greig Andrew , Lindner Hubert , Becker Johannes , Roulston Barret 
Published: November 2018

As part of a major pipeline expansion, two deactivated 24″ diameter pipeline segments with a combined length of 192 kilometres will be assessed and upgraded to operational status. These line segments include a 42 kilometre section within the North Thompson valley of British Columbia, and a 150 kilometre segment through the Rocky Mountains of Alberta and British Columbia.
Reactivating the lines to operational condition is a multi-staged process, which will be partially guided by a National Energy Board Condition requiring the issuance of a certificate from an independent certifying body that the system is fit for service and meets all applicable requirements of CSA Z662, Oil and Gas Pipeline Systems. This certificate must be unconditional and remain in effect for a period of 5 years.
The need for unconditional certification of fitness for service drives the need for a comprehensive assessment of the pipeline condition using a broad slate of inline inspection technologies. Tools were selected for the assessment of deformations, metal loss, manufacturing anomalies and cracking. The lines were maintained with a low pressure nitrogen blanket for between 9 and 13 years prior to the start of the reactivation work and it was therefore not possible to run the tools using service fluid.
Several options were considered for propelling the inline inspection tools including nitrogen, compressed air and water slugs in compressed nitrogen or air. Each method has advantages and disadvantages and modelling was carried out to simulate the transport of the tools through each segment. The modelling needed to account for pipe elevation changes, wall thickness changes, valves, tool drive friction, acceptable tool velocity, and the pressure of the drive medium in the pipeline.
The modelling focused on the following constraints:
i. Ensure ILI data quality
ii. Ensure safety considering the potential presence of defects in the lines
iii. Minimize risk
iv. Minimize overall cost
These constraints guided a flow modelling/feasibility study for inspecting the lines with the 4 tools. The objective of the study was to determine the optimum configuration of propellant, inspection tools, and line segmentation while ensuring a safe, economical operation resulting in optimal data collection.
The paper will provide some background on the line segments being reactivated and pressure limitations that were adopted for ILI runs. The majority of the content will focus on the determination of tool drive technique, how simulation occurred and how the actual execution of the runs compared. Details regarding the challenges and troubleshooting required to successfully complete the integrity surveys will also be discussed in depth.
Risk Assessment for Small Diameter Piping for Liquid Pipeline Facilities
Authors: Ferdous C. M. Refaul , Kulhawy Amanda , Farrell Jessica , Beaudin Chris , Payoe Anthony , Li Lily 
Published: November 2018

The Enbridge Liquids Pipeline system is comprised of a large number of facilities including storage terminals, pump stations, injection sites, and delivery sites. Given the vast amount of small diameter piping (SDP) within company Pipeline facilities, SDP represents a significant portion of total facility integrity risk. An event such as equipment failure or product release can cause significant business impacts, and adverse consequences to the environment and/or safety of operations personnel. A quantitative risk based approach is required in order to establish robust, risk-based plans and programs to maintain the integrity of these SDP sections.
Small diameter piping lengths are relatively short. Consequently, it is impractical to use SDP length as a unit of likelihood and risk measure. Instead, the preferred methodology is to determine the total number of assemblies for each type of SDP. In support of this approach, an inventory of SDP sections throughout the system has been gathered. For illustrative purposes, an example of a small diameter section would be a pressure transmitter branch connection. The isolatable section that would be risk assessed would start from the surface of the main station piping connection and continue up to the transmitter.
This paper presents the framework for likelihood and consequence assessment of SDP based on the system description above. This framework quantitatively estimates the risk of SDP failure and risk-ranks SDP sections in support of implementing and establishing a system wide Risk Based Inspection and Maintenance program for SDP.
Microwave Sensor Array for Corrosion Prediction in Steel Tank Bottoms
Authors: Deif Sameir , Leier Brent , Snow Michael , Daneshmand Mojgan 
Published: November 2018

Throughout North America there are many crude oil storage tank facilities — also called terminals — serving as hubs, transfer points and storage. Safety precautions such as pre-service integrity testing, cathodic protection, primary and secondary containment measures, and grounding techniques have been utilized to assure safety as a top priority. These tanks undergo an in-service API 653 external inspection at least every 5 years, and are taken out of service to undergo an API 653 internal/external inspection at least every 30 years [1], [2], [3]. For these aboveground storage tanks, the bottom plate is the most vulnerable area to corrosion [4] and is also the most challenge area to inspect visually. Both sides (product-side and soil-side) of the tank bottom plate are prone to high rates of corrosion in comparison to other components such as the roof and shell [5]. Corrosion generally starts with coating defects such as air or water ingress to underling layers and exposing the steel to uncontrolled environmental factors.
Internal inspection can be performed using ultrasonic measures to calculate the sheet thickness, however, external inspection is impossible without having access to the tank bottom. This paper will introduce a novel inspection method for external monitoring of the surface of the tank bottom plate in real-time. The proposed technique proactively approaches the problem by predicting the corrosion before it occurs. In this technique an array of microwave-based sensors operating at ISM band (2.57 GHz) are introduced for defect prediction. The array is composed of equally-distant and identical microwave spiral ring resonators (SRR) [6] that are electromagnetically coupled to a transmission line. All resonances created by the array elements merge in one band-stop frequency response with very high isolation. Once the sensors’ environment is altered by any defects such as an air breach, liquid ingress [7] or corrosion initiated, a resonance shift will occur indicating coating risks. To prove the concept, an initial prototype for small tanks of 3–5 ft. diameter is investigated. Two-port system data illustrates that in case of a coating defect, the frequency profile accordingly changes and provides a signature. The obtained data is used to predict possible corrosion in timely manner. The proposed sensor array enables external monitoring of tank bottoms surface where visual inspection is impossible while the tank is in-service.
Compliance Oversight of Operators’ Integrity Management Program for Pipelines: A Risk Based Evaluation Approach Incorporating Safety Culture
Authors: Waheed Bushra , Couch Brodie , Bhuyan Gouri , Iqbal Hassan , Lee Eddie 
Published: November 2018

Integrity Management Program (IMP) is a systematic and documented program for assuring asset integrity throughout the full life cycle of an asset. To ensure safe and reliable operation, the British Columbia Oil and Gas Commission (Commission) has been requiring its licensed pipeline operators through its regulations to develop and implement pipeline integrity management programs (IMPs) in accordance with Canadian Industry Standard CSA Z662. The auditing process, the collated results and findings from the IMP audit years (2011–15) were published in IPC 2016-64161[1].
Since 2016, the Commission has enhanced its IMP compliance assurance process, and aligned it with the management system approach using Deming’s model of plan-do-check-act (PDCA) for IMP components and incorporated a lifecycle approach that spans the entire lifecycle of a pipeline system from planning to abandonment. In addition, the Commission has adopted a multi-criteria decision-making approach when prioritizing which operators to audit. This method utilizes weighted rank approach and takes into account multiple factors, such as, previous IMP audit results, pipeline length and product, class location, incident frequency, and asset age. Through collaborative efforts with the University of British Columbia (Okanagan), an innovative risk based audit tool — Integrity Management Program Audit and Knowledge Tool (IMPAKT) has been developed to help evaluate the compliance of operators’ IMP in terms of the management system approach and its associated risk. This tool conducts three-dimensional analysis of IMP performance using the failure mode effect analysis (FMEA) technique and allows the Commission to generate a risk profile for each IMP component to determine which components are most critical, requiring immediate attention. The final audit results are presented as a Risk Priority Number (RPN), which is a product of severity, occurrence and action. An effective integrity management program requires a strong safety culture, therefore, safety culture aspects are incorporated into the risk based auditing tool, IMPAKT. This risk based evaluation process also allows the Commission to develop a compliance benchmark to make comparison between different operators’ IMP results for continuous performance improvement. This paper presents the innovative approach developed and implemented by the Commission for the IMP compliance oversight (auditing) process and implication of such changes.
Development of Empirical Method to Calculate Natural Gas Pipelines Rupture Exposure Radius
Authors: Ababtain Abdulaziz N. , Aloqaily Arafat M. 
Published: November 2018

Saudi Aramco gas pipeline location classification are designed with a similar approach to the American Society of Mechanical Engineers (ASME) B31.8, which segments the pipeline length and counts the population for each segment. For the segments width, ASME utilizes a fixed distance, i.e., 400 m, while Saudi Aramco uses the pipeline Rupture Exposure Radius (RER), a consequence modeling driven distance similar to ASME’s Potential Impact Radius (PIR). The design factors (i.e., wall thickness requirements) are selected based on the population density within the defined segments, while also affecting the number of segments and emergency isolation valves required along the pipeline.
Previously, Saudi Aramco pipelines safety standards set two default RER values to be used in the pipeline design based on conservative estimates. Based on the pipeline diameter, the RER is set at 1,000m or 2,000m for less than 24″ pipeline and greater than or equal to 24″ in size, respectively.
Saudi Aramco standard defined RER by modelling the downwind dispersion distance at ground level in case of a pipeline full bore rupture to the limit of ½ the lower flammable limit (LFL) of the released vapor cloud, which was shown to be smaller than the standardized values.
As sweet gas pipeline systems are hugely expanding to accommodate the increase in domestic demand in the Kingdom of Saudi Arabia, an efficient method for calculating RER was developed and introduced to the standard. For future pipelines, lower RER distances resulted in more flexibility in route selection, lower pipeline location class, and hence thinner wall thicknesses, less emergency isolation valves required, and longer span between sectionalizing valves, which all translate to cost savings. Existing pipelines currently require less upgrades when encountering urban development in their route, have less number of High Consequence Areas (HCAs) and better repair prioritization.
By statistically analyzing and modeling the Saudi Aramco gas pipeline network, this paper discusses the development of an empirical formula that is representative and less conservative for estimating pipelines flammable gas cloud dispersion ½ LFL. The resulted calculation method had been developed utilizing consequence modeling software, and is expressed as a simple formula as a function of the pipeline pressure and diameter. The established method is currently adopted by Saudi Aramco pipeline safety standards, and resulted in a reduction of 74% of the average pipelines RER, with a standard deviation of 4 meters from the consequence modeling results, and minor diversion in consequence distances when compared to international standards calculation methods such as ASME PIR.
Assessment of Pipeline Spiral Weld Cracks Subjected to Internal Pressure
Authors: Neuert Mark C. , Dessein Thomas J. , Sen Millan 
Published: November 2018

Spirally welded pipelines can make up significant portions of operator transmission systems, and may contain manufacturing anomalies that are susceptible to fatigue growth. Modifications to inputs of crack assessment models, such as CorLAS®, are required to account for the angle these cracks make with respect to the longitudinal pipe axis, given that these crack assessment models were developed for longitudinally orientated cracks. Two such modifications were investigated and are discussed in this paper.
One approach considered the normal stress component perpendicular to the angled crack, for which a stress transformation calculator was developed. Another approach, adapted from API 579 and BS7910 standards, used an effective crack length calculated as the longitudinal projection of the full length of an angled crack.
Failure pressures calculated using these approaches were compared to validated finite element (FE) results. For both modifications, the pressure capacity increased for angled cracks versus longitudinal cracks. The transformed normal stress approach resulted in non-conservative failure pressure predictions with respect to the FE models, whereas the modified crack length approach was conservative.
Additionally, the extended finite element method (XFEM) was used to investigate the propagation behavior of angled cracks. It was found that the general tendency was for propagation parallel to the longitudinal pipe axis; however, when considering weld residual stresses, the crack propagation would be directed toward the direction of the spiral seam.
An Alternative Approach to Time Delay Prior to Inspection for Hydrogen Cracking
Authors: Bruce William A. , Proegler Jared , Etheridge Brad , Rapp Steve , Scoles Russell 
Published: November 2018

Hydrogen-assisted cracking in welds, which is also referred to as ‘hydrogen cracking’ or ‘delayed cracking,’ often requires time to occur. The reason for this is that time is required for the hydrogen to diffuse to areas with crack susceptible microstructures. Prior to inspection for hydrogen cracking, general good practice indicates that a sufficient delay time should be allowed to elapse — to allow any cracks that are going to form to do so and for the cracks to grow to a detectable size. What is a ‘sufficient’ delay time? Why does a delay time tend to be required for some applications (e.g., installation of a hot tap branch connection) and not for others (e.g., construction of an offshore pipeline from a lay barge)? This paper will address these and other related questions and present the results of recent experimental work on this subject.
When determining appropriate delay times prior to inspection, it is important to consider not only the time-dependent nature of hydrogen cracking, but also the expected susceptibility of the weld to cracking. From a time-dependent nature standpoint, longer delay times decrease the chance that cracking can occur after inspection has been completed. From a probability standpoint, if measures can be taken to assure that the probability of cracking is extremely low, then determining an appropriate delay time becomes a moot point. In other words, if the weld is never going to crack, it does not matter when you inspect it. The probability of cracking can be minimized by using more conservative welding procedures (i.e., by designing out the risk of hydrogen cracking during procedure qualification). For example, if hydrogen levels are closely controlled by using low-hydrogen electrodes or a low-hydrogen welding process, or if the hydrogen in a weld made using cellulosic-coated electrodes is allowed to diffuse away after welding by careful application of preheating and slow cooling, or the use of post-weld preheat maintenance (i.e., post-heating), the probability of cracking is significantly reduced, and immediate inspection may be justified. This alternative approach to time delay prior to inspection for hydrogen cracking, which can allow for immediate inspection, will be presented.
Standardization of Flattening Procedure of Transverse to Pipe Axis Strap Tensile Samples
Authors: Rashid M. , Chen S. , Collins L. E. 
Published: November 2018

Tensile testing on large diameter line pipe is generally done using strap samples obtained in the transverse to pipe axis (TPA) orientation of a pipe. The strap samples are then flattened and machined prior to testing. Although the standardized tensile testing is well documented, the variability in the reported TPA tensile properties of the same material tested within a lab or at different labs has always been an issue.
Recent work conducted at EVRAZ NA research lab has identified flattening as the main source of the variability in reported yield strength (YS) values for line pipe. The lack of a standard procedure for flattening TPA strap samples is a major obstacle to obtaining consistent results. Therefore, the main objective of this current study was to establish a standardized flattening procedure for TPA strap samples.
Both finite element analysis (FEA) and experimental approaches were adopted. Various flattening methods and fixtures were studied. Extensive flattening experiments were conducted on TPA samples from different line pipe products.
Results showed that the spring back after flattening in a TPA sample is different for pipes with different gauge and grades. It was established that consistent flattening can be achieved using appropriate fixtures for differerent ranges of tubular products defined by grade, diameter and gauges. Evaluation of the flattening fixture designs and experimental results are discussed in this paper.
Compression Capacity and the Seismic Integrity of Locally Deformed Line Pipes
Authors: Suganuma Atsushi , Kono Junpei , Hayashiguchi Masataka 
Published: November 2018

This paper discusses the effects of local deformation, dent, and strain hardening properties on strain capacity in compression of a line pipe.
Compression tests were conducted using two pipes with the nominal diameter of 400mm. These pipes had roundhouse type stress-strain curve, and correspond to L290 grade in Spec 5L of API (American Petroleum Institute) standards. One pipe was a plain pipe without dent, The other was a dented pipe. The depth of the dent was about 3% of the diameter. The test results explain that the strain capacity can be reduced by 25% due to the effect of dent.
A series of finite element analyses were conducted to investigate the compression behaviors. The strain capacity in compression was defined as the longitudinal critical remote strain whose strain distribution was free from the effects of a dent. At first, that finite element analyses were verified that they could reproduce the results of compression tests. Next, the size of dent were changed on that finite element analyses model, some different case were analyzed in order to investigate the changes of the strain capacity in compression. The strain capacity, the longitudinal critical remote strain, decreased to about a half in case of 3%-depth dent, compared with a plain pipe.
Seismic integrity of the pipeline with a dent is discussed in accordance with the seismic design guideline issued by Japan Gas Association. In case of the strong earthquake, “Ground Motion Level-1”, the dented gas pipeline is safe, even if the depth of the dent is 10% of the diameter. In case of the maximum earthquake, “Ground Motion Level-2”, the gas pipeline might buckle longitudinally in soft ground.
Achieving and Demonstrating Pipeline Engineering Capability: The Role of Competency Standards, and Their Use for Qualifications and Registration
Authors: Harvey Chris 
Published: November 2018

There is increasing pressure on the pipeline industry to be able to demonstrate that its asset management and engineering capability management are at a satisfactory level. This is needed to give policymakers, regulators and industry stakeholders confidence in the safety and environmental sustainability of petroleum pipelines.
Regulators, in particular, are seeking assurance from pipeline owner/operators that they have capable pipeline engineers designing, constructing, operating and maintaining petroleum pipelines. At present, there are no generally accepted approaches to recognising and developing pipeline engineering capability.
The paper will discuss three levels of capability recognition as: (1) registration – as pipeline engineers (not just in mechanical, civil or chemical engineers (overall standing level)) – (2) qualification (sub-discipline/job level) and (3) competency (task level). The most granular and useful of these is competency. This is because it is at the level that is most immediate: the task at hand.
Competency, the combination of knowledge and experience that leads to expertise, is increasingly seen as the best practice basis for learning, particularly for professionals. Significantly, once competencies have been defined in competency standards, they can become the building blocks used to define the requirements for both registration and qualification.
The Australian Pipelines and Gas Association (APGA) has developed a comprehensive competency system for both onshore and offshore sectors. There are 226 onshore competency standards and 57 offshore competency standards describing, in a succinct format, what is required to be competent.
The succinct format of the competency standards avoids the pitfalls of many other systems of competency description, providing enough information to be clear about what is required without unnecessary complexity. In addition to the detailed competency standards, the competency system has tools, resources and a progressive rating scale that make competency standards accessible and easily used. The competency system is characterised by such flexibility that, to date, APGA has identified 15 applications, all of which will add value to engineers and the companies that employ them.
The paper will explain, in detail, APGA’s Pipeline Engineer Competency System, how it works and how it can provide the building blocks for a wide range of tasks that support the training, development and recognition of pipeline engineers’ capabilities, including defining the requirements for registration and qualification.
The paper will provide case studies, based on the APGA Competency System, showing how it can be used to create requirements for qualifications and registration and to design in-house training and development plans.