bluuebunny/crossref_metadata_2025 huggingface dataset:
Pipeline Geohazard Risk Monitoring With Optical Fiber Distributed Sensors: Experience With Andean and Arctic Routes
Authors: Ravet Fabien , Briffod Fabien , Chin Sanghoon , Rochat Etienne , Martinez Jean-Grégoire
Published: November 2018

Many pipelines are built in regions affected by harsh environmental conditions where changes in soil texture between winter and summer increase the likelihood of hazards. Pipeline routes also cross mountains that are characterized by steep slopes and unstable soils as in the Andes and along the coastal range of Brazil. In other cases, these pipelines are laid in remote areas with significant seismic activity or exposure to permafrost. Depending on weather conditions and location, visual inspection is difficult or even impossible and therefore remote sensing solutions for pipes offer significant advantages over conventional inspection techniques. Optical fibers can help solve these challenges. Optical fiber based geotechnical and structural monitoring use distributed measurement of strain and temperature thanks to the sensitivity of Brillouin scattering to mechanical and thermal effects. The analysis of scattering combined with a time domain technique allows the measurement of strain and temperature profiles. Temperature measurement is carried out to monitor soil erosion or dune migration through event quantification and spatial location. Direct measurement of strain in the soil also improves the detection of environmental hazards. As an example, the technology can pinpoint the early signs of landslides. In some cases, actual pipe deformation must be monitored such as in the case of an active tectonic fault crossing. Pipe deformation monitoring operation is achieved by the measurement of distributed strain along fiber sensors attached to the structure. This paper comprehensively reviews over 15 years of continuous development of pipeline geohazard risk monitoring with optical fiber distributed sensors from technology qualification and validation to its implementation in real cases as well as its successful continuous operation. Case studies presented include pipeline monitoring in Arctic and Siberian environment as well as in the Andes which illustrate how the technology is used and demonstrate proof of early detection and location of geohazard events such as erosion, landslide, settlement and pipe deformation.
Earned Schedule and the Use of Schedule Execution Reporting Metrics
Authors: Beck Philip J. , Kovacs Dennis
Published: November 2018

The traditional approach of managing project performance is with the use of Earned Value Management. There is a recent trend towards the expansion of traditional Earned Value Management practices to include the concept of Earned Schedule.

Whereas Earned Value provides insight as to how the project is trending in relation to the plan by assessing cost and schedule variances, Earned Schedule focuses on the time element of schedule performance throughout the project execution phase.

Earned Value, although very effective at providing visibility to cost performance, is not as transparent when it comes to schedule performance over time. Case in point, at completion, irrespective as to how work progressed on the schedule (ahead or behind plan) at completion, the schedule performance index will always be 1.0.

Earned Schedule overcomes this drawback, providing useful tools to report on schedule performance, and providing visibility to the project state from which to base informed decisions.

To perform the analysis, Earned Schedule analysis incorporates detail from the baseline and forecast schedules as well as the integrated project management cost report (earned versus planned). In addition to looking at Earned Schedule metrics, other key metrics are factored into this approach to assess overall schedule performance.

Key metrics derived from the schedule and highlighted in this approach include:

• Critical Path Length Index (CPLI)

• Baseline Execution Index (BEI)

• Total Float Consumption Index (TFCI)

• To Complete Schedule Performance Index (TSPI)

• Predicted Forecast Finish Date (PFFD)

• Schedule Performance Index (time) (SPIt)

• Independent Estimate At Complete (time) (IEACt)

The intent of these metrics is to identify trends and assist in predicting project outcomes based on past performance. Since this approach is highly dependent on the schedule data, the more compliant a schedule is to industry best practices the better the quality of the results. The metrics are negatively impacted by recent re-baselining as this causes us to lose historical performance detail.

Frequent analysis of the schedule execution reporting metrics defined above provides transparency of project performance and brings visibility to early risk triggers in support of a proactive approach to project execution monitoring and control.

This paper will present a case study demonstrating how additional transparency through this approach highlighted a potential schedule risk. This increased visibility allowed the project team to reprioritize and implement proactive corrective actions to mitigate any potential impact to the project In Service Date (ISD).
Using Controlled Global Buckling to Improve Buried Pipelines Performance Under Large Compressive Ground Displacements
Authors: Fathi Ali , Ndubuaku Onyekachi , Adeeb Samer
Published: November 2018

This paper presents the basic concept and verification tests results of a novel method designed to prevent failures of buried pipelines subjected to compressive deformations which are usually caused by ground movements. In this method the boundary conditions of the buried pipes are modified by installing soft elements next to the pipe before backfilling. With the new boundary conditions, the pipe response under large compressive forces will be in form of a stable global buckling mode with a predefined deformed shape. This behavior prevents rapid increase in the compressive axial force that causes local buckling, wrinkling, and subsequent softening, and strain localization. By using this method, pipes can have an extended compressive hardening response that absorbs large compressive displacements. The evaluation of this concept and its performance level were studied through a series of lab tests on 4-1/2 inch pipe specimens under simulated field conditions. The test results confirmed the anticipated performance of this technique which can evolve into a design method.
Numerical Simulation of Pig Motion in Two-Phase Flow Pipelines in the Presence of a Leak
Authors: Patricio Rodrigo A. C. , Sondermann Carina N. , Figueiredo Aline , Viggiano Raphael , Bodstein Gustavo C. R. , Rachid Felipe B. de F. , Baptista Renan M.
Published: November 2018

In the oil and gas industries, it is important to keep pipelines operating at the highest level-of efficiency. This means that a pipeline should not undergo events that may reduce the amount of pumped product at the end of the line. Examples of these events are the existence of debris moving along with the flow, or wax deposited on the pipe wall or the development of a crack or hole on the wall that may lead to the occurrence of a leak. The use of pigs (Pipeline Inspection Gauge) is one of the most common tools for inspection and cleaning of the pipe to restore the optimum pipe operation, despite the uncertainties and risks associated with its passage inside a long duct. For this reason, it is important to follow the pig motion inside the pipeline using numerical simulations. The velocity of the pig depends on the flow dynamics and the pig’s flowing characteristics. This paper presents a mechanical model for the pig motion, along with a numerical scheme, to obtain approximate solutions for the resulting initial-boundary-value problem that describes the pig motion in a transient gas/liquid-flow inside the pipeline in the presence of a leak. The model is formulated as an initial-boundary-value problem of hyperbolic nature. The system of non-linear partial differential equations is discretized within the finite-volume framework and solved using the flux corrected-transport (FCT) method, which is second-order in space. A situation involving a leakage of 10% of total inlet mass flow was simulated and the results are presented for the pig velocity history and for the distribution of flow pressure, velocity and liquid volume fraction along the pipe. In order to validate our results, the commercial software OLGA®, well known in the oil and gas industry, is used for comparison.
Fast Ductile Fracture: Dependence of Propagation Resistance on Crack Velocity
Authors: Bassindale Chris , Wang Xin , Tyson William R. , Xu Su
Published: November 2018

In this paper, the effect of inertia on the steady-state velocity of a propagating crack in a modern high toughness pipeline steel was investigated. The line pipe steel examined in this work was an American Petroleum Institute (API) Standard X70 steel. A tensile plate model, simplified from the geometry of a pipe, was studied using the finite element code ABAQUS 6.14-2. The cohesive zone model (CZM) was used to simulate crack propagation. The CZM parameters were calibrated based on matching the crack tip opening angle (CTOA) measured from a drop-weight tear test (DWTT) finite element model to the experimental CTOA of the material. The CZM parameters were then applied to the tensile plate model. The effect of inertia on the steady-state crack velocity was systematically assessed by altering the density of the material used with the plate model. To isolate the influence of inertia, the effect of strain rate on the fracture process and material plasticity was neglected. The results of this study demonstrate that the steady-state crack velocity was affected by the density of the material. The steady-state crack velocity was reduced with increasing mass density, as demonstrated by the effect of backfill. Furthermore, it was shown that the CTOA extracted from the CZ model was not affected by the density of the model.
Experimental Study on Wax Removal With Real Wax Deposits
Authors: Li Weidong , Huang Qiyu , Dong Xue , Gao Xuedong , Hou Lei
Published: November 2018

Pipeline pigging is one of the most widely used wax remediation techniques in field practice. However, it still depends heavily on “rule-of-thumb” due to the limited understanding of wax deposit properties and wax removal mechanisms. By far, laboratory studies on pipeline pigging generally suffer a gross defect in test materials, i.e., the big discrepancy between the experimental wax samples and real wax deposits. To this end, this paper aims to explore the wax removal in pigging with naturally deposited wax, using a self-designed experimental facility. Wax deposit mass and wax content, two decisive indexes affecting wax removal, were also investigated. The experimental apparatus consists of two parts: a flow loop equipped with a detachable test section to achieve real wax deposits and a wax removal apparatus to perform pigging operations. The test section can be conveniently detached from the flow loop and/or mounted onto the wax removal apparatus for a quick conversion between wax deposition and pigging operation. The results indicate that a higher bulk flow temperature decreases the wax deposit mass and increases the wax content of deposit. Additionally, the distributions of wax content and wax layer thickness suggest that gravity settling plays no role in wax deposition. Moreover, the wax resistive force profile of naturally deposited wax presents four distinct stages, i.e., the build-up phase, the pre-plug phase, the plug phase and the production phase. To the best of the authors’ knowledge, this is the first study on wax removal with real wax deposits. It paves the way for the application of previous artificial-wax-based researches to real wax deposit scenarios.
Investigation of Heavy Sludge Formation in a Chemically Inhibited Sour Gas Pipeline: How Far Do We Have to Go?
Authors: Tajallipour Nima , Cundall Mike , Tong Andy , Delong Terry , Van Boven Greg
Published: November 2018

In this paper a summary of the investigation performed to identify the root causes for the heavy sludge formation in a sour gas pipeline downstream of a gas process plant is provided. The investigation included reviews of historical and current gas and heavy hydrocarbon analyses, particle size analysis, field investigations, operational records, records of cleaning pig runs, and analysis of chemicals used in the upstream process plant and in the pipeline. The strategy undertaken by the operator to manage and mitigate the issue of heavy sludge formation based on the investigation results is also discussed. In the first phase of the investigation, the operational conditions which resulted in sludge formation were investigated but the detailed chemical analysis to determine the mechanism of sludge formation will be performed in the next phase of the investigation, and therefore is not included in this paper.
Effect of UOE Forming Process on the Buckling Strains of Steel Pipes
Authors: Kashani Majid Tanbakuei , Mohareb Magdi , Asadi Mahyar , Smith Mathew
Published: November 2018

Oil and gas pipelines are commonly made of steel pipes manufactured through the UOE process. This process starts with a flat steel plate, bends it into a U shape, then bends it further to form an O shape, welds the seam, and then radially expands (E) the pipe. The process induces significant residual stresses in the pipe wall. Such stresses have conventionally been ignored in past finite element analyses aimed at quantifying buckling strain thresholds. The present study develops a numerical technique to investigate the effect of the residual stresses induced in the UOE process on the local buckling strains of pipes. Two types of nonlinear 3D FEA models are developed to quantify the buckling strains of pipes under imposed bending deformation. The first model starts with a flat plate, models the UOE process to capture the residual stresses, and then subjects the pipes to imposed bending deformation, the second model assumes the pipe is free from residual stresses. Comparisons are then performed between the buckling strains predicted by both models.
An Approach to Engineering Critical Assessment of Assets That Cannot Be Inline Inspected
Authors: Ma Jing , Rosenfeld Michael , Veloo Peter , Rovella Troy , Martin Peter
Published: November 2018

Hydrostatic pressure testing is the most widely accepted approach to verify the integrity of assets used for the transportation of natural gas. It is required by Federal Regulations 49 CFR §192 to substantiate the intended maximum allowable operating pressure (MAOP) of new gas transmission pipelines. The Pipeline and Hazardous Materials Safety Administration (PHMSA) Notice of Proposed Rulemaking (NPRM) with Docket No. PHMSA-2011-0023 [1], proposes an additional requirement for MAOP verification of existing pipelines that: i) do not have reliable, traceable, verifiable, or complete records of a pressure test; or ii) were grandfathered into present service via 49 CFR §192.619(c). To meet this requirement, the NPRM proposes that an Engineering Critical Assessment (ECA) can be considered as an alternative to pressure testing if the operator establishes and develops an inline inspection (ILI) program. The ECA must analyze cracks or crack-like defects remaining or that could remain in the pipe, and must perform both predicted failure pressure (PFP) and crack growth calculations using established fracture mechanics techniques. For assets that cannot be assessed by ILI, however, the implementation of an ECA is hindered by the lack of defect size information.

This work documents a statistical approach to determine the most probable PFP and remaining life for assets that cannot be assessed by ILI. The first step is to infer a distribution of initial defect size accumulated through multiple ILI and in-ditch programs. The initial defect size distribution is established according to the as-identified seam type, e.g. low-frequency electric resistance weld (LF-ERW), high-frequency electric resistance weld (HF-ERW), flash weld (FW), single submerged arc weld (SSAW), or seamless (SMLS). The second step is to perform fracture mechanics assessment to generate a probabilistic distribution of PFPs for the asset. In conjunction with the defect size distribution, inputs into the calculation also include the variations of mechanical strength and toughness properties informed by the operator’s materials verification program. Corresponding to a target reliability level, a nominal PFP is selected through its statistical distribution. Subsequently applying the appropriate class location factor to the nominal PFP gives the operator a basis to verify their current MAOP. The last step is to perform probabilistic fatigue life calculations to derive the remaining life distribution, which drives reassessment intervals and integrity management decisions for the asset. This paper will present some case studies as a demonstration of the methodology developed and details of calculation and establishment of database.
Estimating Landslide Induced Probability of Failure to Pipelines Using a Structured Reductionist Approach
Authors: Guthrie Richard , Reid Emma
Published: November 2018

Much of North America, and indeed much of the global landscape, is comprised of either locally or regionally steep slopes, river valleys, and weak or unstable geology. Landslides and ground movements continue to impact pipelines that traverse these regions. Pipeline integrity management programs (IMP’s) are increasingly expecting quantitative estimates of ground movement or pipe failure as part of pipeline risk management systems. Quantitative analysis usually relies on one or more of statistics, physical models, and expert judgment. Statistics incorporate ground and pipe behavior (for hazard and vulnerability respectively) over a broad area to infer local probabilities. They carry the weight of big data, but the local application is almost certainly incorrect (variability even for regions exceeds 2 orders of magnitude). Detailed geotechnical (hazard) and soil-pipe interaction and stress (vulnerability) models provide rigorous results, but require substantial effort and/or expert judgment to parameterize the inputs and boundary conditions. We present herein a structured tool to calculate probability of failure (PoF) using expert judgment supported by known, instrumented or observable conditions and statistics (where available). We provide a series of tables used as a basis for nodal calculations along a branch path of a decision tree, and discuss the challenges and results from actual application to over 100 sites in the Interior Plains. The method is intended to be a practical informative approach based on, and limited by, data inputs. It is a flexible fit for purpose assessment that takes advantage of the best available data, however, the method relies on the user to articulate a level of confidence in, or the basis of the results.
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.
Inelastic Deformation of Pipelines Induced by Temporary Ground Deformations
Authors: Suzuki Nobuhisa , Arakawa Takekazu
Published: November 2018

This paper describes a new design method to obtain the inelastic deformation of pipelines induced by temporary ground deformations. The proposed design method consists of an elastic solution and a strain conversion procedure which was developed to predict the inelastic strain distribution by using the elastic solution and a stress-strain curve. Roundhouse type, yield-plateau type, and trilinear stress-strain curves are considered. Validation of the proposed method is conducted by comparing the results predicted by the proposed method with the results obtained by finite element analyses.
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.
A New Hydraulic and Thermal Steady-State Calculation Program for Multiphase Pipe Network
Authors: Fan Di , Kang Qi , Zhang Ruochen , Gong Jing , Wu Changchun
Published: November 2018

With the continuous development of offshore oil and gas resources, calculation software for multiphase flowing pipe network has become an important tool for the design and daily operation of multiphase flowing pipe network. Improved accuracy of hydraulic and thermal calculation is an engineering requirement for economic and efficient production. Therefore, a new program is developed for multiphase pipe network in this paper. This program contains a general data structure to describe the complex connection of a pipe network. The structure is based on the conception of the incidence matrix and the adjacency matrix in graph theory. Two processes, hydraulic equilibrium calculation and thermodynamic equilibrium calculation are successively taken in this program to gain the steady-state for a multiphase pipe network. For the hydraulic equilibrium calculation, applying flow equation to each pipe in the network gains a pipe flow vector. A nonlinear system of equations, which represent flow balance of each node, is obtained by multiplying the incidence matrix and the pipe flow vector. To solve these equations, the Newton-Raphson iterative algorithm is used and afterwards, the hydraulic parameters of the pipe network are obtained. For thermal equilibrium calculation, since all the temperature of source nodes is known, the key step is to find the solution order of other node temperature. The program obtains the order by transforming the adjacency matrix. Deng temperature drop formula is used to calculate the end temperature of each pipe. When a node has more than one inflow, an average temperature based on the heat capacity and mass flow is adopted after gaining each pipe’s outlet temperature. Combining hydraulic and thermal algorithms, a complete set of solution program for steady-state of multiphase pipe network is compiled. In the end, two cases are performed to check the accuracy of the program. In the first case, a pipe network is created by using the data collected from a condensate gas gathering network in the South China Sea. The result indicates that the program has a good agreement with the actual data. In the second case, the program is applied in a single-phase network and gains almost the same result calculated by PipePhase and PipeSim.
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.
Evaluation of Hydraulic Fracturing Models and Their Limitations to Predict No-Drill Zones for Horizontal Directional Drilling
Authors: Delara Saeed , MacKay Kendra
Published: November 2018

Horizontal directional drilling (HDD) has become the preferred method for trenchless pipeline installations. Drilling pressures must be limited and a “no-drill zone” determined to avoid exceeding the strength of surrounding soil and rock. The currently accepted industry method of calculating hydraulic fracturing limiting pressure with application of an arbitrary safety factor contains several assumptions that are often not applicable to specific ground conditions. There is also no standard procedure for safety factor determination, resulting in detrimental impacts on drilling operations. This paper provides an analysis of the standard methods and proposes two alternative analytical models to more accurately determine the hydraulic fracture point and acceptable drilling pressure. These alternative methods provide greater understanding of the interaction between the drilling pressures and the surrounding ground strength properties. This allows for more accurate determination of horizontal directional drilling limitations. A comparison is presented to determine the differences in characteristics and assumptions for each model. The impact of specific soil properties and factors is investigated by means of a sensitivity analysis to determine the most critical soil information for each model.
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.