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Materials, Design, and Construction

2019;():V001T01A001. doi:10.1115/IOGPC2019-4506.

Critical offshore pipelines require extremely low D/t (Outer diameter to wall thickness ratio) pipes, that pose a manufacturing challenge using conventional practices and operational toolings. Such pipes are most often manufactured through the seamless route, due to the D/t ratio. But seamless pipe are more expensive as compared to welded pipes, along with having higher lead times due to fewer manufacturers. There is also a concern with the uniformity of wall thickness throughout the pipe body due to the manufacturing process, but with an advantage of better properties citing homogenous composition due to absence of a weld seam. Though in the last couple of decades, owing to advances in the welding technology, the weld seam of a welded pipe has proved to be superior to the base metal plates/coils in terms of its strength integrity.

To manufacture such pipes through the LSAW (Longitudinal Submerged Arc Welded) process requires major overhauling and process modifications at practically all the stages of the process flow. The low diameter and high wall thickness become very demanding when it comes to bending the plate and then welding (SAW) from the inside due to space constraints.

This paper describes in detail the challenges faced and overcoming of the difficulties in manufacturing an 18″ diameter, 35 mm wall thickness LSAW pipe (D/t ratio of 13) for a major oil & gas player, by development of new designed toolings for various equipment like plate crimping, pipe forming and mechanical expander; new lubrication oil; and optimizing the process parameters, as the major factors contributing to success. The tooling design modifications were done in-house, along with the development of a new lubrication oil and its treatment in plant. This enabled Welspun Corp to surpass the equipment capacities prescribed by the OEMs, and set a new benchmark in the industry for the production of extremely low D/t welded pipes, with excellent mechanical properties along with impeccable pipe dimensions.

Topics: Manufacturing , Pipes
Commentary by Dr. Valentin Fuster
2019;():V001T01A002. doi:10.1115/IOGPC2019-4510.

Hydrocarbons are the major source of energy in the world. While the global energy demand continues to rise, the shallow water hydrocarbon reserves currently under production are getting exhausted. This has encouraged all major E&P (Exploration & Production) companies around the world to look towards exploration and development of newer deepwater offshore reserves, hitherto largely left untouched. Furthermore, gas reserves-rich nations are also showing a keen interest in exploring new gas markets to boost their exports and, in the process, provide a solution to the energy scarcity of other parts of the world.

The two factors mentioned above — the need for newer energy reserves and the urge to tap new energy markets — coupled with the safety, reliability, and cost-effectiveness of pipelines have contributed to the growing number of deepwater gas pipeline projects being executed around the world.

“Deepwater Pipelines” per se is not a new concept. Many deepwater pipelines have already been installed in different parts of the world. However, for the Indian energy sector, this is a relatively new development, with the exception of KG basin deepwater pipelines. The Indian government’s HELP (Hydrocarbon Exploration and Leasing Policy) and proposed trans-national submarine gas pipelines are likely to serve as the harbingers of future deepwater pipeline projects in Indian oil & gas sector.

Although the technical and codal requirements for deepwater pipelines are the same as that applicable for any shallow water offshore pipeline, there are a few nuances that must be considered extremely important to successfully implement any deepwater pipeline project. This paper elucidates the deepwater pipeline considerations such as pipeline route selection, flow assurance, line pipe material & wall thickness selection, pipeline installation analysis, seabed intervention techniques, alternative integrity validation (AIV) etc.

Topics: Design , Pipelines , Testing
Commentary by Dr. Valentin Fuster
2019;():V001T01A003. doi:10.1115/IOGPC2019-4512.

Reliance Industries Limited (RIL) planned to import liquid Ethane from North American market for use as feedstock in Gas Crackers at Dahej Manufacturing Division (DMD), Hazira Manufacturing Division (HMD) in the state of Gujarat and Nagothane Manufacturing Division (NMD) in the state of Maharashtra. Liquid Ethane was planned to be unloaded at GCPTCL (Gujarat Chemical Port Terminal Company Limited) Jetty and stored in cryogenic tank in DMD. For use in NMD and HMD, it was proposed to transport Ethane via a dedicated pipeline traversing through the states of Gujarat and Maharashtra and deliver at respective gas crackers of HMD and NMD in a direct usage mode as no storage facilities for Ethane were envisaged at delivery locations. Reliance Gas Pipelines Limited (RGPL), a wholly owned subsidiary of RIL implemented the Asia’s 1st liquid Ethane Pipeline project as “Dahej - Nagothane Ethane Pipeline Project” (DNEPL) and successfully commissioned the pipeline in September, 2018. This paper presents the Conceptual Design of the project including selection of phase of transportation, pipeline configuration in terms of pipeline size, no. of pump stations, spacing of main line valves (MLV’s), operating conditions, material of construction and emergency evacuation requirements of Ethane during long haul transportation.

Commentary by Dr. Valentin Fuster
2019;():V001T01A004. doi:10.1115/IOGPC2019-4519.

API 5L grade steel is mainly used for oil and gas transportation. The economy of gas transportation via pipeline demands for high operating pressures and large pipe diameters in order to improve transportation capacity which requires heavy thickness and/or high grade of the steel. This pushed the steelmakers to develop high strength steels (HSS) with superior metallurgical and mechanical (strength, toughness and ductility) properties in order to allow exploitation in hostile environments. The technology of production of API 5L grade through conventional thick slab process is matured enough as it gives flexibility of using higher %C, lower casting speed, high slab thickness (200–250 mm), higher reheating temperature and time, high reduction etc. However due to slower cooling rate during liquid to γ transformation, possibilities of centerline segregation defect increases. Thin slab technology (TSCR), on the other side allows a reduction in energy consumption (because of lower slab thickness and elimination of reheating process), with consequent benefits in terms of production costs and pollution reductions. But producing API X65 and above though TSCR route with subzero impact and DWTT is a challenge because of the difficulties in achieving a refined and homogeneous microstructure due to lower reduction ratio from slab to finish sheet thickness. This paper aims to give an overview of recent developments of high strength pipe steel grades as API 5L X70 through TSCR route. Information regarding the metallurgy and processing, such as chemical composition, microstructural design, thermo-mechanical controlled process (TMCP) and accelerated cooling process (AcC), to achieve the target strength, ductility and toughness properties are discussed. Mechanical properties are well above the requirement of X70 at HR stage as well as after pipe formation. Excellent Impact and DWTT is achieved up to −40° C.

Commentary by Dr. Valentin Fuster
2019;():V001T01A005. doi:10.1115/IOGPC2019-4540.

This paper explains the complexity in marine tanker loading of highly waxy RJ Crude via Single Point Mooring System at Bhogat Terminal. It mainly presents the key challenges in temperature sustenance of Rajasthan Crude in the marine pipelines during the tanker loading operation. It also presents how the pump logic and valve closure timings are configured to prevent high pressure surge in the system.

Due to the waxy crude characteristics of Mangala Crude, it is required to always maintain the Crude temperature above its Wax Appearance Temperature of 65 Deg C. As the marine system partly consists of non-heated section like the under buoy and the floating hoses, it was required to simulate the temperature losses in the system and provide a pipeline flushing sequence at the end of the operation. Various flow and operational scenarios are modelled in OLGA and recommendations are implemented for the system. Similarly, Surge analysis was performed in PIPENET to determine acceptable valve closure timing for the tanker valves, breakaway couplings (BAC), SPM and PLEM valves to prevent overpressure in the marine system.

Based on the transient simulations, temperature loss during RJ crude export (at 4,636m3/hr) from terminal to the tanker in 24 hours is negligible (less than 10 Deg C). This indicates that the insulations in the pipelines are adequately designed for preventing heat loss. Whereas, the temperature in the hoses falls below 42 Deg C within 12 hours of shutdown which may lead to wax formation and may block the hoses. Therefore, RJ crude is to be flushed out of the system using flushing oil before it can cool to below its wax appearance temperature of 65 Deg C. It is recommended to insulate the bare pipe-works such as the PLEM, SPM and tanker if possible to facilitate a reasonable response time for setting up flushing oil displacement. It is also recommended that the pipelines are heated to 50 Deg C prior in advance of commencing flushing oil displacement operations to terminal and in preparation for RJ crude export.

Based on the hydraulic surge analysis, a closure time of 30 seconds is acceptable for PLEM valve closure. It is recommended to trip the export pumps at loading arm pressure High High of 7 bara. However, closure of both the breakaway couplings (BAC) cause pressure surges which exceed the MASP of the hoses for BAC closure times of 10 to 60 seconds.

Topics: Temperature , Surges
Commentary by Dr. Valentin Fuster
2019;():V001T01A006. doi:10.1115/IOGPC2019-4541.

The current scenario of HSLA line pipe welded with critical parameters by Automatic Submerged Arc Welding being widely used in critical services for both onshore & offshore, also challenging to achieve stringent mechanical properties i.e low temperature toughness, hardness, YS/TS ratio, etc. Recent studies proved that the Ti-B wires been widely used to weld line pipes which gives higher fracture toughness values at lower temperature. In this experiment, an attempt has been made to maintain the volume fraction of acicular ferrite by alloying elements in weld metal with variation of low to high heat input range. The purpose of this experiment is to determine the effect of different alloyed wire with respect to critical welding parameters on mechanical & Metallurgical properties. This investigation also includes metallographic changes, role of different alloying elements for improving the microstructure and distribution of inclusions in weld metal, which directly affects the mechanical properties of weld metal. Based on the results, Optimization has been done which is focusing on welding consumables from the existing chemistry to find at what extent the variation of chemistry causes undesired metallurgical changes in the weld metal and also how it influences the mechanical properties of welded line pipe.

Commentary by Dr. Valentin Fuster
2019;():V001T01A007. doi:10.1115/IOGPC2019-4574.

SECON developed GIS Database and Web based Pipeline Information Management System (PIMS Application) covering all the pipelines and facilities across the country for which work has been awarded to SECON Pvt. Ltd., Bangalore.

This database comprises of different map layers and associated tables pertaining to pipeline alignment, stations and facilities, dwellings and structures along the pipeline alignment, pipeline depth of cover, points of interest along the route etc.

Topics: Pipelines
Commentary by Dr. Valentin Fuster

Quality Governance in Pipelines

2019;():V001T02A001. doi:10.1115/IOGPC2019-4539.

The coating and cathodic protection protect pipeline against the corrosion. The failure of these two defense systems leads to corrosion failure of pipelines. Any changes in chemical, physical or electrochemical properties of coating which affect their properties to isolate tFhe pipes from the corrosive atmosphere is considered as failure of coating. The failure mechanism and the gap analysis need to be continuously done for improvements in specifications and its executions. Majority of the global oil and gas pipelines are being protected externally with either 3-Layer Polyolefin coating system or fusion bonded coatings. Some of the gas pipelines are provided with a flow improvement internal coatings considering nil corrosive challenges on internal surfaces. The failures in the external coating appear in the form of edge disbondment from cutbacks and near holidays, complete loss of adhesion of coating, loss of cohesion within coating, cracking in the coating, swelling & blistering around holidays, distortions in the coating, electro osmosis, electrophoresis and highly alkaline atmosphere near holidays, continual increase in CP currents and corrosion of the substrate. The internal surfaces of pipes are suffering corrosion mainly due to presence of corrosive gases viz. carbon dioxide, oxygen, condensates and other corrosive substances even in traces. The common methods like Dehydration, Inhibitors, Buffering, Biocide and Cleaning pigs are not adequate to protect the pipelines to from the corrosion. A very thin internal flow coat can hardly resist any corrosion and gets failed.

This paper presents the in-depth analysis of the major causes of coating failures and the improvements required in the external and internal coating selections, specifications, coating applications, testing and its maintenance.

Topics: Coatings , Pipelines , Failure
Commentary by Dr. Valentin Fuster
2019;():V001T02A002. doi:10.1115/IOGPC2019-4570.

Quality parameters in petroleum products HSD/SKO/MS are being ascertained on the basis of IS standards and accordingly every OMC produces petroleum product. These products are transferred from refinery to receiving terminals through, rail, road or cross country pipelines. In a particular instance, one of the pipeline fed location in BPCL were continuously getting Haziness in diesel batches.

This location was Kota terminal in Rajasthan state and the scenario was such that receipts taken through their MMBPL pipeline was Hazy in appearance. The hazy batches were required to keep ideal for almost 3–4 days to clear its appearance, however all other parameters were meeting the QC guidelines / IS standards.

The peculiar behavior depicted in HSD batches was only at their end pipeline location (Kota), on other intermediate locations at upstream of Kota location, the same HSD batches were passing the appearance test. The study was undertaken to know the root cause for such phenomenon and on the basis of RCA , corrective action were implemented for altering the manufacturing process of HSD.

Commentary by Dr. Valentin Fuster
2019;():V001T02A003. doi:10.1115/IOGPC2019-4594.

Small bore connecting (SBC) systems, including small bore piping (SBP), Small bore tubing (SBT) and Flexible Hose Assemblies (FHA) with size below DN 2″, are significant contributor to the incidences of Loss of Primary Containment (LOPC) and are a major source of failures in piping systems.

Modern hydrocarbon installations feature large numbers of control and monitoring instruments, which require a considerable application of SBT assemblies, along with enormous number of threaded fittings and joints. However, the basic expectations from these SBTs will remain to provide the integrity over the entire life cycle of the installation.

One of the estimates from standard database (Courtesy: Energy Institute Guidelines, year 2013) indicate that 20.4 % of all hydrocarbon leaks recorded in the Hydrocarbon Release (HCR) data were related to SBTs. Of these events, over half were classified as major or significant HCRs events (notionally an amount greater than 1 kg) linked to SBT assemblies.

With complexity and extensive applications, SBT assemblies are vulnerable to failure due to incorrect design, selection, installation, operation, modification, inspection & maintenance and could result into events of LOPC and Major Accident Hazards (MAH).

Despite availability of guidelines for design and installation, failures in SBT assemblies continue to occur in operational phase. Lack of formal procedures, inconsistent controls to manage the biggest contributors to HCR on assets, signifies the requirement of a structured approach to achieve Asset Integrity. Then there arise a question “is small bore connection systems an Achilles heel of Asset integrity?

This paper covers, an in-depth analysis of few LOPC events, of geographically different installations, related to SBTs with an aim to achieve overall Asset Integrity through

a. Verification of availability of sufficient barriers, between safe operation & incident.

b. Effective management of threaded connections in existing SBT assemblies with respect to relevant ASME standards.

c. Practical guidelines for providing preventive and recovery controls barriers for an effective management of SBTs.

Topics: Tubing
Commentary by Dr. Valentin Fuster

Integrity Management

2019;():V001T03A001. doi:10.1115/IOGPC2019-4537.

When a single source based crude oil feeder ‘difficult-to-pig’ pipeline runs through a highly sensitive marine national park, the Operator is challenged with the dilemma of how to assure the integrity of the pipeline with the limited options that are available.

After ten (10) years of service, in 2015, an Indian Operator chose to assess the time dependent threat of internal corrosion on their difficult-to-pig offshore (SPM) to onshore (Tank Farm) crude oil pipeline by utilizing the NACE SP0208-2008 Standard for Liquid-Petroleum Internal Corrosion Direct Assessment (ICDA). This methodology was already recommended by ASME B31.8S as one (1) of the three (3) options for assessing integrity of a pipeline. Only a year earlier, in 2014 – the Indian regulators, Oil Industry Safety Directorate (OISD) had also brought the technique of ICDA within its regulatory framework for Operators as a credible option to assess integrity of pipelines that are difficult to pig and/or un-piggable.

This paper discusses on the findings of the ICDA program that forced the Operator to accelerate their integrity program for the subject pipeline and perform specialised In-line Inspection (ILI) in 2018. The paper also compares the results obtained from the non-intrusive predictive based ICDA program Vs. the ILI measured data.

This paper will be useful for Operators to understand the complementary nature of ICDA with ILI and provide guidance on how combination of these two (2) pipeline integrity tools not only identify the locations at which internal corrosion activity has already occurred but also answers the questions on why it occurred and how would it be mitigated?

The Operator managed to assure the integrity of their “difficult-to-pig” pipeline by timely utilisation of the integrity validation tools of ICDA and ILI. By doing this they were able to prevent the occurrence of any catastrophe that may result in an environmental, and subsequently an economic disaster.

Commentary by Dr. Valentin Fuster
2019;():V001T03A002. doi:10.1115/IOGPC2019-4555.

Pipelines are one of the safest forms of transportation for oil and gas. However, Pipelines may experience defects, such as corrosion, cracks during service period. Therefore, evaluation of these defects is very important in terms of assessment and for continued safe operation. Corrosion defects at the external surface of pipelines are often the result of fabrication faults, coating or cathodic protection issues, residual stress, cyclic loading, temperature or local environment (soil chemistry). In general, corrosion may occur in most pipes due to coating failure, and a pipe without any protective coating will experience external corrosion after some years. However, corrosion can occur on the internal surface of the pipeline due to contaminants in the products such as small sand particles.

At present, there are different assessment methods for different types of defects in pipelines. The most popular codes for defect assessment in oil and gas pipelines are RSTRENG, Modified B31G, BS 7910 and API 579. Besides these codes and methods, there are numerical programs, such as CorLAS, which have been used successfully for assessing crack flaws in Pipelines. RSTRENG and B 31G methods are very simple when compared with API 579. API 579 is very complex method of assessing defects but very useful for remaining life assessment of Pipelines.

In this paper corrosion defects like general metal loss, localized metal loss, pitting corrosion, other defects like dents, gouges, cracks, their remediation methods assessed based on API 579 method and our experience in Oil Pipelines. Since API 579 doesn’t cover cross country pipelines explicitly, we have made a research applying API 579 to ASME B31.4.

Even though, we have done research on all types of defects (Level 1 and Level 2 assessment), in this paper we have covered only General metal loss assessment.

Commentary by Dr. Valentin Fuster
2019;():V001T03A003. doi:10.1115/IOGPC2019-4568.

More than 80% of crude oil requirement in India is met through imports. Imported crude oil is delivered to the shore tanks through Single Point Mooring (SPM) system. Generally, SPM systems are installed in the sea where water depth is around 30m and more. Crude oil tankers discharge their cargo through these SPMs and off-shore pipelines to storage tanks located in the shore. Therefore, off-shore crude unloading pipelines are a vital link to in the energy supply chain in India. Management of these off-shore pipelines is a challenging task. This paper discusses a case of mechanical damage to an Indian off-shore pipeline and how the damage is being evaluated to ensure reliability and safety of this vital link to ensure sustained and safe operation of the line. The mechanical damage discussed in this paper is in a 48″ off-shore pipeline at a depth of nearly 30m and 24km away from the shore. Owners believe that the damage was caused due to anchor hit from a ship that was buffeted away from safe anchor zone to no anchor zone during a cyclonic storm. Owner had to face considerable challenge in locating and measuring the extent of damage and evaluating its severity and probable impact on the integrity of the pipeline. Owner had done multiple geometry inspection of the pipeline to measure the length of the damage and restriction introduced in the bore due to local reduction in diameter. Possibility of presence of a crack and its likelihood of growth in the near and distant future is also evaluated. The paper also discusses the possible remedial measures to ensure long term integrity of the pipeline.

Commentary by Dr. Valentin Fuster
2019;():V001T03A004. doi:10.1115/IOGPC2019-4588.

Pipeline integrity is essential for reliable pipeline operations, for preventing expensive downtime and failures resulting in leaking or spilling oil / gas content to the environment. Leaks can cost industries millions of dollars in loss of energy, while increasing emissions, creating safety hazards, and lowering the reliability of operations. Valves and piping systems can fail in a number of ways. Pipelines are widely used for transportation of fluids like oil & natural gas over long distances to the power plants, public supplies and various industries due to safety, efficiency and low cost. High pressure pipelines are generally buried below the ground level for safety, economic and environmental purposes. For smooth and safe operation of pipeline, there are some associated facilities underground as well above ground facilities like Valves, IJ, Fittings, Launcher & Receiver known as pipeline system. To maintain the integrity of the pipeline system, these facilities need periodic maintenance for their effective operability up to their design life. Valves are one the critical component of the pipeline system and failure of it may cause serious hazard and reduce the control over the various parameters like flow & pressure in the pipeline. Shutting down to repair the leak means a loss in associated industry’s production leading to revenue loss.

Darod - Jafarabad Pipeline (DJPL) is one the Natural Gas Pipeline laid by Gujarat State Petronet Limited (GSPL) to transport natural gas in the coastal region of Saurashtra in Gujarat. DJPL is a 212 KM long pipeline with 10 nos. of SV stations. There was leakage observed from bolted body of Ball Valve installed at Intermediate Pigging Station (IPS) and SV-6 of DJPL and these valves are butt welded and in upstream side which need shutdown of pipeline for maintenance or replacement. Maintenance of valve becomes critical, if there is gas leakage from valve body and the pipeline operation cannot be obstructed due to commitment with downstream customers. In such a situation, Stopple-in is the method to isolate the valve without obstructing / shutting the flow in the pipeline. The valves were in upstream side wherein replacement of valve was done by Stopple-in and Cross plugging method. However, gas leakage was from valve body so that hot work (i.e. pipe cutting) for stopple-in was also a challenge. To arrest the leak from bolted section of valve body, sealant injection methodology was adopted. Before applying this technology on high pressure live pipeline, GSPL insisted to perform the demonstration on prototype arrangement. This prototype was manufactured in the way that it has a manmade leakage point. After sealant injection in the system to arrest the leak, system was kept under high pressure of 55 Bar(g) for 24 hours. During demonstration, system sustained the pressure without any failure at leakage point. After successful demonstration, said methodology applied on leakage valve installed on high pressure line without any shutdown to arrest the leak.

Topics: Valves , Leakage
Commentary by Dr. Valentin Fuster
2019;():V001T03A005. doi:10.1115/IOGPC2019-4591.

As per Indian regulations (OISD-STD-141, OISD-2014-SOP, PNGRB T4S, PNGRB IMS etc.), the mandatory requirement for the operators is to perform Cathodic Protection (CP) and/or Coating Integrity above ground survey every five (5) years.

The individual Indirect Inspection (IDi) technique or techniques used for such surveys are Closed Interval Survey (CIP) On/ Off, Direct Current Voltage Gradient (DCVG), Current Attenuation Testing (CAT) and Alternating Current Voltage Gradient (ACVG). These techniques primarily assist in evaluating the CP performance, coating condition of the pipeline and locations of probable DC/ AC interferences. Usually these surveys are performed separately and integrated by their respective GPS coordinates to get a common chainage.

As per prevailing practice in India, typically the pipeline operators perform a Closed Interval Survey (CIP) On/ Off survey and after reviewing the reports subsequently plan for conducting DCVG, CAT and/or ACVG for certain stretches only, where CIP indications are found. By the time the team is re-mobilized for these surveys the pipeline or environment conditions may be totally different. This may be due to season variability, accuracy of GPS (mapping, if at all conducted during the coating integrity survey), climatic conditions, access to right of way (RoW) due to cultivation / farming cycles, water table variance and eventually fluctuations in the insitu soil resistivity. In addition, interference from other CP sources in the RoW, which may have occurred during interim. All of this can lead to misalignment or incomplete analysis of the integrated consolidated survey data.

In addition, these “indirect inspection” surveys are majorly dependent on the experience and training of the surveyor, resulting in extensive subjectivity on the survey results with very limited traceability of collected data. This is unlike the other integrity tools for assessing integrity of a pipeline, such as In-line Inspection (ILI) as well as hydrostatic testing, wherein it is compulsory to provide the pipeline owner recorded footprint of the raw data collected for authenticity.

For the CP and coating integrity surveys, if these can be performed simultaneously along with workable recorded raw logs for each survey with recorded GPS position of the surveyor, for further analysis, this does lead to eradicating the subjectivity from the IDi surveyor and providing “true” authentic repeatable results. This paper provides case studies wherein results of legacy IDi surveys are compared to the results of performing all surveys together along with recorded raw logs.

Commentary by Dr. Valentin Fuster
2019;():V001T03A006. doi:10.1115/IOGPC2019-4597.

Operators decommission older offshore oil and gas fields for a variety of reasons: regulations and business models change, technology improves, field productivity ceases.

In many cases, the existing pipeline network around these platforms is repurposed or reconfigured to suit current needs. New production wells can be tied in to the existing network, and unproductive assets can be bypassed and decommissioned. Although the platforms are most often specific in purpose, the pipelines are generalists by nature. Prolonging the life of this type of asset is almost always profitable.

This paper describes how in-line isolation technology kept production loss to a minimum during offshore platform decommissioning and the tie-in of a reused pipeline into a new facility.

Commentary by Dr. Valentin Fuster

Safety and Integrity of City Gas Distribution

2019;():V001T04A001. doi:10.1115/IOGPC2019-4520.

Polyethylene pipes and Steel pipes with 3LPE coatings are integral part of a citygas distribution network. These are being used in India since late 80’s. Standard MDPE and HDPE materials are Butene copolymers of Ethylene, where Butene (C4) is added as comonomer to form the side branches of linear Polyethylene (C2) chains. The research on PE materials have improved various attributes of the polymer, providing them with higher durability, pressure resistance and service life.

One such development is use of Hexene (C6) as a copolymer replacing Butene (C4) to make an Ethylene Hexene copolymer providing superior resistance to mechanical damages and slow crack growth during installation and service. For PE100 Orange pipe materials for low / medium pressure distribution system, the new hexene PE copolymer, offers much superior resistance to slow crack growth. Hence it is ideal for Trenchless installations like HDD or pipe bursting, where pulling the pipe through the bore in the ground may substantially notch and scratch the pipe or coating. Using a Hexene PE service life of the pipe is not affected despite the demanding installation techniques due to higher entanglement of polymer chains. These types of PE materials are already being used by Indian CGD Industry for past 2–3 years.

For 3LPE coated steel pipes for high pressure gas mains as well as trunk lines, Hexene based Black PE top coat has been adopted by several Gas companies. This is mainly due to two advantages. They offer a higher upper design temperature limit of +90 C (compared to +80 C as per international specification (ISO21809-1). They also offer material savings as 10% lower thickness compared to standard PE top coat is able to meet and exceed all system requirements. The paper deals with the mechanism of these new polymers that helps to offer these superior properties.

Commentary by Dr. Valentin Fuster
2019;():V001T04A002. doi:10.1115/IOGPC2019-4521.

The Government of India is promoting usage of PNG in cities and metros in big way which has opened up newer opportunities & challenges for the CGD industry especially catering to Domestic, Commercial & Industrial Consumers meeting the existing regulations & statutory provisions. As per the Provisions of Petroleum and Natural Gas Regulatory Board (Technical Standards and Specifications including Safety Standards for City or Local Natural Gas Distribution Networks) T4S Regulations domestic piping should be in ventilated area. However, currently there is no clear-cut technical guidelines for installation of piping downstream to consumer meter in concealed location and confined spaces. This study suggests guidelines provided in various codes & standards and the practical approaches adopted in various countries for installation of the pipe-work between the Service Regulator (SR) up to and including the steel reinforced rubber hose installed inside the kitchen of the domestic customer, and includes the risers and laterals systems supplying gas to high rise multi occupancy buildings (domestic premises), to facilitate supply of gas to the domestic customers.

Commentary by Dr. Valentin Fuster
2019;():V001T04A003. doi:10.1115/IOGPC2019-4576.

“A Web Based City-GIS system to manage City Gas distribution Network”

CityGas is a web based GIS system capable of handling city gas network by maintaining up-to-date information in centralized enterprise database, providing support for analysis, engineering, O&M, planning activities and acting as a valuable decision support system for planning & emergency response. CityGas is an effective marketing tool for gas distribution companies.

Commentary by Dr. Valentin Fuster
2019;():V001T04A004. doi:10.1115/IOGPC2019-4582.

There are some issues and concerns that need urgent attention. Chief among these are delays in securing multiple clearances, lack of well-defined market potential, entry barriers, deficient pipeline connectivity and uncertainty regarding domestic gas supply. The challenges during the reward of license revolve around issues affecting project Internal Rate of Return (IRR), project investment rate of return, market exclusivity, gas allocation, gas availability issues, logistic and manpower issues. With the formation of PNGRB, the safety practices and guidelines were looked into and framed. But once allocation process is over and operation is in progress, there are still several challenges that are being faced as:

• Safety Management

• Space Constraint for CNG station facilities

• Queue Management

• GIS for CGD network

• Third party damages

• Coordination with other utility Companies

• Compliance of emission norms

• Equipment Availability

• Customer satisfaction (Services, Metering, billing)

• Threat of alternate energy solutions

• Embrace digital technology in conjunction with analytics intervention.

• Compliance of stringent targets by the ministry.

For IGL, being into the operation at the capital of the nation the major concern with CGD is safety, customer friendly operation and on-time solutions. This paper will discuss in detail the work adopted by IGL to cater the problem of space constraint, queue management and external threats. Apart from this, it also covers the various technologies and automation strategies adopted towards safety system, metering, billing, equipment availability etc.

CGD companies must embrace digital technology in conjunction with analytics intervention to enjoy technology renaissance. It will help in achieving improvements and address issues in PNG, CNG and management of assets, among others. Emphasis will be given to provide a few such initiatives in detail, mentioned above, such as the pilot project going for HCNG plant, SCADA system for online monitoring of equipment, GIS system for pipeline integrity, automation of safety system and customer satisfaction.

Commentary by Dr. Valentin Fuster
2019;():V001T04A005. doi:10.1115/IOGPC2019-4583.

Indraprastha Gas Limited (IGL) is India’s biggest organization in the field of City Gas Distribution (CGD) and this has happened by overcoming the several challenges from the electrical aspect also. Following are some of the initiatives taken from the electrical aspects to contribute in the growth of the company:

1. Installation and commissioning of the CNG set-up at Retail Outlets (RO) of the Oil Marketing Companies (OMCs) and Dealer Owned Dealer Operated (DODO) sites.

2. In-house installation and commissioning of the UPS with redundancy scheme at CNG re-fueling stations.

3. In-house installation and commissioning of the LED lights in place of the conventional lights (MH/HPMV).

4. In-house installation and commissioning of the Gas Generators in place of Diesel Generators.

5. In-house installation and commissioning of the 15HP VFDs in place of conventional motor starters for running the air compressors and specific engine driven gas compressors (1200 SCMH) through Gas Generators.

6. In-house installation and commissioning of the 11KV/0.4KV Package Sub-Station (PSS) of different ratings.

Commentary by Dr. Valentin Fuster

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