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ASME Conference Presenter Attendance Policy and Archival Proceedings

2017;():V001T00A001. doi:10.1115/IOGPC2017-NS.
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This online compilation of papers from the ASME 2017 India Oil and Gas Pipeline Conference (IOGPC2017) represents the archival version of the Conference Proceedings. According to ASME’s conference presenter attendance policy, if a paper is not presented at the Conference by an author of the paper, the paper will not be published in the official archival Proceedings, which are registered with the Library of Congress and are submitted for abstracting and indexing. The paper also will not be published in The ASME Digital Collection and may not be cited as a published paper.

Commentary by Dr. Valentin Fuster

Pipeline Design, Construction and Project Management (Onshore/Offshore) - Oil and Gas

2017;():V001T01A001. doi:10.1115/IOGPC2017-2418.

This paper discusses the pounding tuned mass damper (PTMD) — a novel device developed in a joint collaboration between OneSubsea, a Schlumberger Company and the University of Houston to absorb and dissipate the undesired vibrations generated due to VIV and FIV in subsea pipeline and jumpers. The PTMD is based on principles of both the tuned mass damper (TMD) and the impact damper. The tuned mass in the PTMD absorbs the kinetic energy of the structure and dissipates the absorbed energy through collisions on viscoelastic material. During development, detailed numerical analysis and experimentation were performed to study the effectiveness of the PTMD on the jumper. In the experiment, a full size M-shaped jumper was tested in both air and shallow water conditions for VIV at NASA’s Natural Buoyancy Laboratory (NBL). The experiment also examined the robustness of PTMD for different frequency VIVs. Experimental results showed that the PTMD effectively reduced the in-plane and out-plane vibration of the jumper up to 90%. The observed reduction in vibration amplitude can reduce fatigue damage to jumpers, thus enabling oil and gas operators to optimize spending on vibration mitigation devices, minimize lost revenues, improve system lifespan and availability, and enhance operational flexibility. Reduction in stress of these pipelines also means improved reliability and reduction in costs associated with inspection, maintenance, and repair of subsea jumpers and pipelines. These long-term financial benefits and ability to be installed on existing and new jumpers (pipelines) makes the PTMD a desired solution for vibration suppression in deep water environments.

Commentary by Dr. Valentin Fuster
2017;():V001T01A002. doi:10.1115/IOGPC2017-2429.

Seabed features along a subsea pipeline route are highly stochastic. Free spans may be created in the pipelines due to seabed irregularities, subsequent scouring, and horizontal movements of pipeline during operation. It is quite common to encounter free spanning sections along the pipeline route from the very start till the end. Spanning of subsea pipelines is a primary area of concern not only in the detailed design and installation stage but also during the operation stage. For ensuring the pipeline safety during operation, underwater surveys must be conducted at suitable intervals. The frequency of such pipeline free spanning surveys depends on the operators’ interest and the statutory requirements. The static and dynamic characteristic of the pipeline spans should be investigated to ensure that the pipeline can be operated within acceptable safety levels. The unsupported spans that incur static as well as dynamic loads on the pipeline, may lead to vortex-induced vibrations and ultimately fatigue, and thus affecting the pipeline serviceability and design life. Vortex induced vibrations are not allowed to occur in the operation life as far as the conventional design is considered but DNV - RP - F105 allows the onset of vortex induced vibrations provided that the fatigue damage due to vortex induced vibrations doesn’t exceed the allowable values. Pipe soil interaction has a huge impact on the pipeline design as well as the pipeline service life. Analysis of the existing conditions and stress levels based on the site-specific surveys and environmental data needs to be carefully carried out for determining the acceptability of spans and the effective intervention works if required. Hydrological studies and numerical modeling may also need to be carried out for sediment transportation analysis and for proper assessment & quantification of sea bed erosion, trenching and backfilling requirements.

In the present work, the acceptable criteria in terms of static and dynamic stresses and fatigue damage limits due to vortex induced vibrations as per DNV - RP - F105 have been discussed. Further comprehensive analysis philosophy and the criticalities in the design analysis for free spanning of subsea pipeline are presented. A case study based on an offshore project in western India has been presented involving the major project issues. The main areas of concerns & challenges faced are examined in detail. Further study has been conducted for the other available strategic solutions in the VIV mitigation and rectification of free spanning sections.

Commentary by Dr. Valentin Fuster
2017;():V001T01A003. doi:10.1115/IOGPC2017-2431.

With the advent of automated measurement of physical dimensional parameters of steel line-pipes, the industry seems to have scaled newer heights, which were previously never even imagined. The dimensional accuracy of each pipe is very critical in the overall success of a line pipe project. The quality of girth welding of pipes during laying, depends upon the close dimensional tolerances of the pipe ends. Even a slight variation in out-of-roundness or end-chamfered profile could lead to drastic irregularities in the pipe-to-pipe joining process. And the manual measuring of the pipe parameters poses a serious question with regards to their accuracy and reliability, due to the effects of man, measurement method and instruments used. There is also a huge limitation of the sampled area measured not exactly resembling the whole pipe, due to the constraints of time and the manual process involved.

This paper describes the rise of Automated Pipe Dimension Measurement System (APDMS), which measures a total of 19 dimensional parameters after real-time geometrical & trigonometrical calculations, using parametric data from 72 measurement laser scanners & sensors. The pipe coordinates are measured by laser triangulation technique principally, at each degree circumferentially and 10 mm apart lengthwise. A pipe that needs at least 45 minutes to measure all dimensional parameters manually, by 2 men and almost 25 instruments & accessories, is measured in 2.5 minutes by APDMS with mind-boggling resolution and accuracy. All this is done with a simple push of a button after one-time entering of pipe size. The fully automated system then does its job efficiently to move the pipe accordingly and scan it. The back-end software calculates the required parameters from the measured raw coordinates, evaluates them against set criteria, viz. upper and lower limits, and generates a plot that shows the variation of a parameter along the length or circumference. A calibration system in incorporated to keep the system compliant with accuracy against calibrated and certified standard samples.

Initially, we took more than 2000 trials on the whole range of pipe sizes we manufacture, after the installation of system on shop-floor. After trials and establishment, we have so far measured more than 3000 regular production pipes through this system with remarkable results.

Analysis has been carried out continuously to ensure the repeatability and reproducibility of the system is as per industry standards. This new, contactless method aims to minimize dimensional variances for fluent and effortless installation of pipes at application site, by ensuring that the dimensions are well within the defined criteria, at each and every point on the pipe during its manufacturing.

Topics: Dimensions
Commentary by Dr. Valentin Fuster
2017;():V001T01A004. doi:10.1115/IOGPC2017-2433.

Over the years the drilled river crossing industry has matured through important developments and advancements, extending the probability of achieving significantly longer crossings. Stronger rigs, higher quality drill pipe and smart intersect survey techniques are a few of the areas showing improvement. Executing a long length crossing involves a high competency level from personnel, high quality reliable equipment and general construction resources over a longer period of time as compared to a more standard HDD crossing. Consequently a relatively large financial investment is necessary and significant cash flow capabilities. This requires drilling companies to step up job preparation, planning and overall organisation and to follow a detailed scenario with each step of the operation assessed and engineered, tools and support equipment selected and arranged and checked with all work methods written down in detail. Providing an elaborate plan and organisation to guarantee maintenance and repair of all sorts of equipment on site with systems in place to stock, trace and deliver wear & tear parts at short notice. Preventing the operation coming to a standstill caused by technical problems.

Commentary by Dr. Valentin Fuster
2017;():V001T01A005. doi:10.1115/IOGPC2017-2463.

Transportation of crude oil and liquid petroleum products through cross country pipeline for inland movement & through jetty/SPM for export/import has been a very common phenomenon across the world.

M/s Cairn India Ltd. (“CIL”) are the operator of block RJ-ON-90/1 in India and operate the block on behalf of itself and its Joint Venture (JV) partner - Oil and Natural Gas Corporation (ONGC). The Block contains a number of major oil discoveries including the Mangala field in the state of Rajasthan, India.

M/s Cairn India Ltd. (“CIL”) have approval from Government of India (GOI) for a pipeline to transport crude oil from the Block at Rajasthan to coastal terminal facility in Gujarat and recently commissioned the facility for exporting Mangala crude oil through marine tankers from our Bhogat Terminal safely.

The facilities & export operations for crude oil at our Bhogat Terminal is very unique and , specific in nature — especially due to properties of crude oil & mainly considering following aspects.

(I) Handling Mangala crude oil containing significant quantities of wax & it is expected to congeal at temperatures below 50°C.

(II) Crude oil is always required to be kept heated for maintaining temperature > 60°C – Handling crude with specific properties and scenario w.r.t. normal liquid petroleum products.

(III) Displacement of crude oil with Light Flushing Oil (LFO-HSD being used as LFO) from twin marine headers and subsea/floating hose strings after every tanker loading operation & recovery of light flushing oil back to shore tank prior to every export tanker loading. – Safely managing a very distinguished & highly critical/risky nature of operations to prevent congealing of crude oil inside subsea/floating hose systems which cannot be provided with heating system.

Commentary by Dr. Valentin Fuster

Materials for Pipelines

2017;():V001T02A001. doi:10.1115/IOGPC2017-2404.

The selection of pipeline materials requires consideration of design, construction, operations, maintenance, threats, hazards, risks, safety and economics. Codes and standards provide mandatory and optional requirements and guidelines for the selection of materials. Experience and industry practice help to develop and implement requirements beyond mandatory and code minima, and to augment the achievement of safety and realization of the value of pipeline assets. Both codes and experience get updated over time. When selecting and using materials for pipeline systems, it becomes important to meet with code essentials, while simultaneously recognizing the recommendations of design engineers, materials specialists, manufacturers, installers and operators.

There is a wide gamut of materials that can be considered for pipeline systems. These include metallic and non-metallic materials. While steels are still used as the workhorse material in the industry, several non-metallic materials are gaining prominence. These include thermoset materials, for example, reinforced plastics, and thermoplastic materials, such as high-density polyethylene.

In addition to pipe, there have been significant developments in other pipeline component materials, such as for valves, fittings, flanges, gaskets, seals, adhesives, bolts and nuts. Considerable advancements have also taken place in the realm of joining and repair methods, for metallic and non-metallic materials. Many of these materials and methodologies are of a proprietary nature, with limits on how much information is divulged by the manufacturers and producers, and what is subject to information that is shared based on confidentialities. Proprietary materials, especially non-metallic products, and some corrosion resistant alloys, are generally not extensively addressed in codes and standards, especially in comparison with steel-based materials that are of the commodity type. Some internationally recognized specifications and standards address the requirements for the qualification of pipeline components, including pipe, fittings, flanges and valves, based on non-metallic materials. Other internationally recognized standards and specifications address the requirements for apparently commodity type materials and materials that are considered to be generally corrosion resistant and relatively long lasting, however, can be susceptible to failure when subjected to specific threats.

This paper provides an overview of the process of selection of pipeline materials addressing the above considerations and gives an outline for the implementation of such a process. It describes ways in which a balanced approach to the use of codes and standards that are necessary for regulatory and mandatory compliance, and the application of the benefits of proprietary materials that are available for commercial purposes can be achieved. Thereby, the optimization of asset life cycle and augmentation of safety and reliability during pipeline operations can be enabled.

Commentary by Dr. Valentin Fuster
2017;():V001T02A002. doi:10.1115/IOGPC2017-2417.

In line with the government of India’s philosophy of going green to reduce emission levels in cities there is a thrust to increase the gas distribution network. With an increase in CNG vehicles, comes the safety of the people and we need to ensure that Safety is not comprised at any level.

To follow the Safety aspect, CNG is an excellent alternate fuel which can be used to minimize risks and increase life of the vehicles. Since this gas is used at very high pressures (in the range of 230–250 bar) and under severe conditions, special tubing must be used for the transportation to gas stations and in the vehicles. Therefore, the tubing should be able to not only withstand high pressure of the gas within but also the corrosion issues arising due to the extreme conditions the tubes within.

Sandvik did an extensive study of the conditions and came up with a material which is specifically developed for this high pressure application. The high pressure line is of Stainless Steel 316L but this material comes with certain modifications for this particular requirement. In this tubing the C content is lowered to 0.025% for better corrosion resistance, Ni is min 13% along with Mo min 2.5% this makes sure that the material not only has sufficient passivation properties but the strength also to withstand that kind of a pressure. Alongside a special production route also has been developed for the manufacturing of these tubing. This ensures Safety for the people throughout the life of the vehicle.

Commentary by Dr. Valentin Fuster
2017;():V001T02A003. doi:10.1115/IOGPC2017-2453.

Three Layer Polyethylene (3LPE) coating for onshore pipelines have been used in India since the early 1980’s and have reached a level of maturity. The combination of Gas barrier by FBE layer and moisture barrier with mechanical and UV protection by black PE layer makes it better than either standalone FBE or 2LPE coatings. Further developments in PE materials makes 3LPE coating suitable for a design temperature range of −50°C to +90°C which practically covers all the onshore Oil pipelines in all geographies with excellent outdoor weathering resistance. It has also been possible to provide end-to-end protection with new PO Melt film technology that can give “factory applied” quality girth weld coating on site with complete fusion of girth weld coating with the parent coating, making it a hermetically sealed pipeline. This paper also discusses couple of the failure and success stories of 3LPE coating and their analysis.

Topics: Coatings , Pipelines
Commentary by Dr. Valentin Fuster
2017;():V001T02A004. doi:10.1115/IOGPC2017-2464.

Hot pushed induction heating is a bending process used to bend pipes having a small bending radius with a large diameter. This is a complex process since it involves mechanical process of bending and thermal process of localized induction heating. This paper deals with the optimization of induction bending process parameters such as bending speed, water flow rate, water pressure, air pressure and induction coil to water coil distance. Mother pipes of size 464 mm OD × 20.60 mm and grade API 5L X65MS/MO were used to make trial bends of 5D radius in 30° angle. Trial bends were subjected to mechanical tests and microstructural analysis to evaluate the effects of selected process parameters.

Commentary by Dr. Valentin Fuster

Pipeline Integrity Management

2017;():V001T03A001. doi:10.1115/IOGPC2017-2419.

Unprecedented flooding in Narmada River in August 2013 caused massive bank erosion at the pipeline crossing location leading to snapping of three pipelines and exposing few others except Reliance Gas Transportation Infrastructure Limited (RGTIL’s) EWPL. All these pipelines were laid by conventional trenchless HDD method wherein the landfall point was located at a relatively safe distance from the bank line. The current velocity at the crossing location being higher during floods coupled with weak bank strata, suitable and tangible measures were required to be taken to protect the pipeline from the shore line to the land fall point in the event of reoccurrence of such an incident. The depth profile of EWPL pipeline from the shore line to the landfall point varied from −18 metre to −3.5 metre from the existing ground level which prompted RGTIL to neglect conventional methods like Pipe anchoring and Installation of rock filled gabions involving massive excavations which could have further destabilized the already fragile bank. In view of the prevailing soil conditions and construction difficulties associated with it, RGTIL adopted an innovative method of Installation of Sheet piles on the upstream and downstream of the pipeline to retain the soil around the pipeline and thereby preventing its exposure. Sheet piles are generally used as temporary structures to retain soil for facilitating deep excavations, as retaining system for large waterfront structures etc. These were perhaps never used in India earlier for any pipeline protection works.

Commentary by Dr. Valentin Fuster
2017;():V001T03A002. doi:10.1115/IOGPC2017-2428.

Safe Pipeline transportation of energy resources is a major concern. Every Natural Gas Pipeline Operator’s primary objective is to operate and maintain pipeline network in such a way that it would continuously provide un-interrupted services to customers without any accidents which can adversely impact on the environment and reputation of the organization. Various surveillance methods are being used in Natural Gas Pipelines as a part of direct integrity assessment. Traditionally, surveillance is conducted by line walking and supplemented by vehicular over the linear corridor. This process involves various shortcomings in terms of efficacy, accuracy, cost, and safety. This method purely depend upon Inspector’s ability for detecting anomalies. It is in the interest of any operator to maintain the value of its pipelines and to protect them effectively against damage caused by third parties. As a result of global progress in high-resolution remote sensing and image processing technology, it is possible to use digital surveillance method for monitoring of pipeline Right of Use (RoU). Digital Surveillance is done using Remote Sensing and Geographical Information System (GIS) techniques. Remote sensing based pipeline surveillance refers to the monitoring and detection of changes on RoU and around pipeline networks. This paper elaborates on the development and implementation of a digital solution that uses images from satellites and Unmanned Aerial Vehicles (UAV) to detect instances of encroachments and third-party activities on Pipeline RoU. Such a solution provides capability of running advance analytics on captured images, and will enable to automate detection of anomalies which may often go un-noticed during manual inspection.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2017;():V001T03A003. doi:10.1115/IOGPC2017-2438.

The inner surface of pipe plays a crucial role in top of line corrosion when condensation of droplet takes place. Condensation over inner periphery of pipeline takes place by droplet formation due to differential temperature inside the pipe and external environmental factors. To understand the change in corrosion rates with respect to droplet flow and temperature [40°C, 60°C and 80°C], a rig with curvature 80mm which simulates top of line corrosion is designed to carry out experiments at 0°, 15° and 30° inclinations in fixed 3 litre beaker.

Droplet formation on the sample as well as on perpex surface has been captured at different temperatures to understand the droplet size formation. Corrosion rate calculation is done my weight loss methods which are generally preferred in on site analysis instead of electrochemical measurements. Surface analysis is carried out with the help of optical microscope and optical profilometer where corrosion rate, inclination were correlated to average surface roughness.

Topics: Corrosion , Pipes
Commentary by Dr. Valentin Fuster
2017;():V001T03A004. doi:10.1115/IOGPC2017-2439.

Pipelines are recognized as one of the safest methods of transporting hazardous products, however unwanted incidents still occur. With many kilometers of the pipelines interacting with different environments, they are exposed to various threats and risks. Any record of leak or rupture along the pipelines can have devastating consequences; for example extreme environmental impacts, huge economic losses in addition to its national and international operators’ images.

To prevent pipeline failure and adhere to the regulations, the risk of an incident to occur should be continuously assessed and evaluated throughout the pipeline’s operating life-cycle. Risk management has been a critical component of the Integrity Management Process (IMS) for a number of years. With the increasing availability of geographic information and improved inspection technologies for pipeline networks, there is an on-going expectation from both pipeline regulators and operators worldwide to access a more quantitative approach for risk management along the pipeline using GIS or geoprocessing models.

Amalgamation of geoprocessing models with integrity management allows to precisely identify the risk areas along the pipeline with a rich visualization on the map. This is one of the most critical element underpinning the decision-making process.

In this paper, a review of geoprocessing tools that have been implemented within a pipeline integrity management system is presented. Examples of these geoprocessing tools include: (1) Class Location, (2) High Consequences Area (HCA), (3) Gas Dispersion and (4) Electrical Interference. After successful implementation of these tools, the output of the tools have been used to carry out more detailed analysis of risk assessment and aid in decision making. Additionally a WebGIS platform was also implemented to facilitate the visualization of the results.

Commentary by Dr. Valentin Fuster
2017;():V001T03A005. doi:10.1115/IOGPC2017-2443.

The network of pipelines worldwide is growing and aging which leads to an ever increasing focus towards integrity management of these pipelines. One major challenge faced by today’s operators is the realization and management of corrosion of pipelines. Unless detected, sized and documented correctly corrosion does pose as a major time-dependent threat to the aging pipeline network which eventually, if undetected and uncontrolled, can lead to catastrophic failures.

Inline inspection (ILI) by means of intelligent pigs is widely used to ensure a safe operation of pipelines. Ultrasonic technology (UT) is currently the most accurate and reliable inline inspection technology available in the market. Highly specialized UT ILI tools can detect and size pipeline threats related to corrosion or cracking. High resolution tools as available today allow for the reliable inspection of tiny corrosion defects such as pittings or even pinholes. These small but often deep anomalies are severe forms of corrosion known to have caused pipeline failures in the past.

The economic environment for oil companies has changed significantly in the last few years where reduced prices and margins for oil transportation and production challenge pipeline operators globally. At these tight margins, operators must scrutinize closely the indirect costs of performing inspections. Any constraints imposed by required inspections have the potential to negatively affect margin, including the reduction of pipeline flow rates to accommodate optimum inline inspection conditions. The latest generation of UT tools offer higher inspection speeds which overcome the need for flow reduction, therefore reducing transportation losses due to the reduction of throughput. In addition, there is also a need for enhanced axial and circumferential resolution to enable reliable detection and sizing of e. g. pinhole corrosion defects. Without the necessary measuring resolution these defects otherwise might go undetected and un-accounted for. In this contribution, the latest improvements of ultrasonic ILI are described and illustrated by inspection results.

Commentary by Dr. Valentin Fuster
2017;():V001T03A006. doi:10.1115/IOGPC2017-2445.

This paper will review the history of pipeline repairs. Prevailing codes, standards , design guidance’s and regulation typically permit several types of repairs: namely: replace pipe as a cylinder, repair by grinding or buffing out a defect, weld overlays techniques, utilizing a steel reinforcement sleeve or utilizing a composite reinforcement sleeve or composite wrap. This paper will review the history of the technology and the efforts to document and codify consensus standards such as ASME PCC 2 Article 4.1, ASME B31.8s, ASME B31.4 and ISO 24817. Contemporaneous issues related to the subject will be addressed as well of the durability of the aforementioned repair methods.

Globally pipeline operators are required to operate their pipelines in a safe and reliable manner, preventing any unplanned loss of containment, and ensuring the asset continues to run reliably delivering a profit for the pipeline owner/operator. Most pipeline operators are required to maintain their pipelines to an approved code either by National Regulators and/or insurers with the aim of improving safety of the pipeline and unplanned losses of containment. Most National Regulators guidance for the repair of pipelines refers to either ASME B31.4 for liquid pipelines and B31.8(S) for gas pipelines, while for process piping most operators complete repairs following the ASME PCC2 Article 4 guidelines. These guidelines are credible and are globally accepted as being an effective method to operate and maintain pipelines. This paper with reference to the three ASME guidelines highlighting the acceptable repair methods and also looks at the requirements of ISO TS 24817 and highlights how this does and does not fit into the maintenance of high pressure pipelines.

Commentary by Dr. Valentin Fuster
2017;():V001T03A007. doi:10.1115/IOGPC2017-2448.

Flow modelling and corrosion risk assessment are used to study a challenging multiphase pipeline, where the main focus is the identification and prioritization of critical locations for direct inspection (DA). Through the internal corrosion direct assessment (ICDA), flow modelling sensitivity studies is carried out to identify critical locations with risks of high shear stresses and water holdup. Through corrosion risk assessment (CRA), the critical locations were narrowed down to four primary locations, which through direct inspection could provide the information necessary to estimate the overall pipeline condition. It is highlighted that without the In-line inspection (ILI) data, selection of inspection locations becomes problematic. However, carrying out a CRA in combination with dynamic flow modelling can build a more representative analysis and assist with effective engineering decision making.

One of the available industry standard tools that can assist with demonstration of pipelines’ integrity requirement is an approach that integrates flow assurance with corrosion modelling known as Internal Corrosion Direct Assessment (ICDA). More specifically, an industry standard multiphase dynamic flow model (OLGA) with well-established corrosion models, CRA and engineering judgement have been employed to identify and prioritize inspection locations.

A benefit of this work is the validation of predictions by both OLGA and the corrosion engineer in close adoption to the procedures of the NACE ICDA standard practice. Considerations from corrosion engineering aspect on modelling requirements and corrosion diagnosis will be presented, where the primary focus is on identification of hot spots and consequent inspection requirements in order to limit excavation activities and provide cost-effective solutions to the client.

Commentary by Dr. Valentin Fuster
2017;():V001T03A008. doi:10.1115/IOGPC2017-2449.

Contaminants such as CO2, H2S and O2 in liquid and gas pipelines in the presence of water create an aggressive environment conducive to internal corrosion. During pipeline operations, solids deposition, water accumulation, bacterial activities and improper chemical inhibition aggravate the internal corrosion attack. For assessing the threat of internal corrosion the industry has only three integrity validation tools at its disposal. These are Pressure Testing, In Line Inspection (ILI) and Internal Corrosion Direct Assessment (ICDA). To enhance pipeline integrity for piggable and non-piggable pipelines, NACE International published a variety of Standard Practices for the ICDA protocols for predicting time-dependent internal corrosion threats for various products in both offshore and onshore in sweet or sour service.

All ICDA protocols are a structured, iterative integrity assessment process, consisting of the following four steps: Pre-assessment, Indirect Inspection, Detailed Examination and Post-assessment. Most importantly, unlike ILI and pressure testing, all ICDA standards require a mandatory root cause analysis and a go forward mitigation plan to arrest the corrosion processes being encountered.

This paper reviews one case study; LP-ICDA for three (3) “piggable” refined product pipelines from the Jetty to the onshore marketing terminal. This paper will be useful for the pipeline operators to provide guidance on not only identifying the locations at which internal corrosion activity has occurred but also look into how the operators used the ICDA program to better manage their asset.

Topics: Corrosion , Pipelines
Commentary by Dr. Valentin Fuster
2017;():V001T03A009. doi:10.1115/IOGPC2017-2465.

Risk Based Inspection (RBI) is a risk assessment and management process that is focused on loss of containment of pressurized equipment in processing / transportation facilities, due to material deterioration / degradation. These risks are managed primarily through threat identification, inspection, monitoring and mitigation measures. Risk Based Inspection (RBI) process is focused on maintaining the mechanical integrity of high pressure pipelines and minimizing the risk of loss of containment due to deterioration. Frequency of inspection & monitoring activities are fixed in cost effective way which based on the risk ranking.

This paper discusses the development, implementation and maintaining a risk-based inspection (RBI) program for high pressure long petroleum pipelines. It provides guidance to operators of pressure-containing pipelines for developing and implementing an inspection program. This technical paper includes means for assessing an inspection program and its plan. The approach emphasizes safe and reliable operation through risk-prioritized inspection and monitoring program. This also includes practical implementation case study of Wolrd’s longest heated crude oil pipeline operated and maintained by M/s Cairn India Limited.

Commentary by Dr. Valentin Fuster

Health Safety and Environment (HSE) and City Gas Distribution (CGD)

2017;():V001T04A001. doi:10.1115/IOGPC2017-2410.

Laying of petroleum and natural gas pipelines requires Clearances pertaining to Environment, Coastal Regulation Zone (CRZ), Forests and Wildlife from various statutory bodies of the Central and State Government depending on the proposed pipeline route. Because of the time-consuming appraisal process undertaken at various levels, planning the statutory approval process forms a very important part of the project implementation schedule. The project proponents have to forecast and plan well in advance for obtaining statutory approvals as scheduled.

This paper details the clearances required for pipeline projects mainly from environmental angle, the procedures involved and difficulties faced by project proponents. It also suggests project proponents to plan the activities in advance and be updated on the new guidelines and notifications issued by the authorities. It also puts forth some recommendations to Statutory Authorities to simplify the procedures for speedy disposal of proposals related to pipeline projects.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2017;():V001T04A002. doi:10.1115/IOGPC2017-2415.

Cross country pipeline construction, as an industry, may be 65 years or even more, the equipment, the methodology and technologies in this industry have not changed significantly as compared to other industries. The same accident reoccurs on one pipeline project after another even though the incidents are investigated and reports are published and root causes are known to management and communicated to workforce. Pipeline construction activities are hazardous, fast paced, strenuous and are undertaken simultaneously at remote sites, with limited access making it difficult to monitor and control. Experience shows that the time spent on pre-construction and planning activities is simply rapid during construction phase of the work, when safety issues can be much more difficult to resolve. Road driving is another area of concern as lot of travelling is involved. Strategic, focused application of Health, safety and environment programs and its monitoring and mitigation will significantly improve the safety performance of the pipeline construction areas while improving the overall motivation of workers and time schedule to complete the project. These achievements have been demonstrated through the development and implementation of strategic and focused HSE management programs that identifies the areas of concern along the pipeline in the field and allocating the right type of resources in time to mitigate the probability of incidents. Pipeline construction industry will prosper in twenty-first century only if everyone at every level understands the importance of these safety issues and implement the practices that will safeguard both people and planet.

Commentary by Dr. Valentin Fuster
2017;():V001T04A003. doi:10.1115/IOGPC2017-2422.

Hazardous area classification or zoning is a method of analyzing and classifying the environment in which explosive gas atmospheres may occur to facilitate the proper selection and installation of equipment to be used safely in that environment. In several oil and gas companies, hazardous area classification is carried out as an integral step of the risk assessment exercise to identify areas where controls over ignition sources are required on the rigs. In this paper, one example of such an exercise is presented. The recommendations from the exercise were used in updating the company’s guidelines on zoning and eventually improving the fire safety of its operations.

The paper discusses these factors and their impact on zoning.

Commentary by Dr. Valentin Fuster
2017;():V001T04A004. doi:10.1115/IOGPC2017-2452.

City Gas Distribution is one of the most assured businesses in current times as Natural Gas being a clean fuel becomes the first choice of consumers.

Though CGD Network has enormous potential and has evident advantages however, it brings alongwith it’s own challenges but the biggest challenge is the vicinity of CGD Network with common public. A major factor for success of CGD Network depends on the discipline and involvement of common public in keeping CGD Network safe and effective.

This paper intends to discuss on HSE issues with focus on like Single Call system for India, Indian regulations Vs other countries and Quality Assurance.

Single Call system for India is the most important issue of CGD Network that really needs to be deliberated. In India, more than 20 clearances need to be obtained from various statutory and civil authorities before execution of any CGD Network project which really affects the project cost, time, consumer benefits, emergency response and third party damages.

Now let’s consider few international regulations like National Energy Board in Canada which is the nodal agency to ensure CGD pipelines are safe for public and environment. NEB regulations harmonize with provinces to ensure that any third party excavation work within pipeline corridor is carried out only after due communication to the pipeline company.

The 49 US Code 60114 - One Call notification system also mandates that any third party before carrying out any excavation needs to establish if there are underground facilities present in the area of the intended activity and contact appropriate system.

Indian regulations like T4S and ERDMP for CGD Network are indeed bringing all CGD companies at par in terms of design, safety, O&M and Integrity Management System. However, they need to sincerely look into Single Call System alongwith specific issues like interdistances, space constraints in big cities, compressor installation at height.

Quality Assurance involves periodic inspection and maintenance of CGD asset through a systematic plan including identification of critical equipments, Preventive Maintenance Schedules, carrying out maintenance as per the PM, maintaining a database of observations and defects. A key component is the generation of baseline data for implementing and monitoring Integrity Management System for CGD Network.

Hence, as CGD Network is a complex and dynamic distribution system involving public, private industries/commercials, civil authorities and wide geography, it is imperative to have a multi-pronged approach involving strict regulation enforcement, well informed public and latest technologies to ensure safe and efficient CGD Networks.

Commentary by Dr. Valentin Fuster

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