Offshore World - April May 2016 by Offshore World

VOL.13 | ISSUE 3 | APRIL - MAY 2016 | US $ 10 | ` 150

OFFSHORE WORLD

INSIGHT INTO UPSTREAM & DOWNSTREAM HYDROCARBON INDUSTRY

Engineering Procurement Construction APRIL - MAY 2016 VOL. 13 ISSUE 3 Mumbai ` 150

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CONTENTS

INTERVIEW ‘It’s not just technology that makes a difference to enterprises, but the business models being used’ - Sanjay Joshi, Country Manager and Managing Director, Aker Solutions India

VOL. 13 | NO. 3 | APRIL - MAY 2016 | MUMBAI ` 150 OFFSHORE WORLD R.NO. MAH ENG/ 2003/13269 Chairman Publisher & Printer Chief Executive Officer

EDITORIAL

Editor Features Writer Editorial Advisory Board Design Team Subscription Team Production Team

Jasu Shah Maulik Jasubhai Shah Hemant Shetty Mittravinda Ranjan (mittra_ranjan@jasubhai.com) Rakesh Roy (rakesh_roy@jasubhai.com) D P Mishra, H K Krishnamurthy, N G Ashar, Prof M C Dwivedi Arun Parab Dilip Parab V Raj Misquitta (Head), Arun Madye

‘Indian petroleum market growth is encouraging’ - K Ravi, Chief Operating Officer, Bharat Oman Refineries Limited

Moving towards Recovery - Cairn India

Focus Areas in EPC Projects in Oil & Gas Industry – Project Management in Practice - A M Joshi & Dr Hariharan Subramanyan

Pollution Control Measures in Refinery and Downstream Petrochemical Plants - Ajay Popat

Modularization of Liquefied Natural Gas Facility - Sushant G Labhasetwar

NEWS FEATURE

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FEATURES

An Offshore 48” Oil Pipeline ‘Successfully’ inspected through Internal Corrosion Direct Assessment - Bidyut B Baniah & Ashish Khera, P Eng

Getting the Green Light on the Grey Matter - Ron Beck & Sunil Patil

Challenges of Upgrading Diesel Quality from BS III, IV to BS VI in India - Akshay Choudhary, Nihar Ranjan Beuria & M K E Prasad

Energy commodities turnaround to move up - Niteen M Jain & Nazir Ahmed Moulvi

NEWS

PROJECT UPDATE

PRODUCTS

EVENTS DIARY

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INTERVIEW

‘It’s not just technology that makes a difference to enterprises, but the business models being used’ ‘The entire oil & gas industry is now focused on cost effective project execution strategies in order to make the industry sustainable even at lower oil prices. It is up to us to ensure our people and processes can keep up with these requirements’, says Mr. Sanjay Joshi, Country Manager and Managing Director, Aker Solutions India. In a candid interaction with Rakesh Roy, he articulates about the shifting focuses in project management strategies, customer expectations, technology developments and various other key concerns in the changing business environment of the oil & gas sector.

Today, large oil and gas projects are becoming increasingly complex and technologically demanding. The prevailing tough market conditions require lean project budgets, with an emphasis on optimized and cost efficient solutions in design, execution, and operations.

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Offshore World | 6 | April-May 2016

INTERVIEW How has the project management strategy in oil & gas projects changed with the changing business environment? Today, large oil and gas projects are becoming increasingly complex and technologically demanding. The prevailing tough market conditions require lean project budgets, with an emphasis on optimized and cost efficient solutions in design, execution, and operations. In this scenario, project management has to be dynamic and focused on delivering the best value through the best solutions. Sometimes this involves innovation and cuttingedge technologies, while in other cases it’s a matter of reworking existing solutions to do things faster, better and cheaper. We have launched #thejourney, a global improvement program across Aker Solutions. #thejourney encompasses all our improvement efforts – and we see that it is delivering real, tangible results. The goal is to increase cost efficiency across the business, and share these benefits with our clients. We are building a stronger culture of continuous improvement, as well as a competitive and sustainable organization. Aker Solutions is also actively looking at partnering with various companies to provide complete, comprehensive, and holistic end-to-end solutions to our customers in order for them to derive the most value out of such partnerships. What are the challenges faced by engineering service providers regarding the customers’ changing expectations? As a services provider to oil & its allied industries, how does your organization respond to these challenges? The entire oil & gas industry is now focused on cost effective project execution strategies in order to make the industry sustainable even at lower oil prices. It is up to us to ensure our people and processes can keep up with these requirements. Operational excellence is at the core of Aker Solutions’ strategy as we seek to forge a sustainable future for our industry and the world it serves. We are systematically increasing efficiency by analyzing our deliveries and eliminating tasks that do not add value for the customer. To help us with this, as part of or global improvement program #thejourney, we are rolling out Lean methodology and tools across our operations globally. This method of working has already demonstrated significant reductions in lead-time and project man-hours, cost reductions, simplification of processes, and more. How has the oil and gas market changed as the industry has gone from the shallow reservoirs of the past to deepwater? The global need for oil and gas grew by about 1 million b/d in 2015, averaging about 94 million b/d. This trend is expected to continue, with a projected consumption of about 96 million b/d in 2017. Developing deepwater reserves will be essential to ensure that supply meets demand.

Accessing reservoirs at greater depths requires complex technology, which can result in a very high E&P spend for operators. This kind of capital expenditure needs careful deliberation considering the drop in oil prices, which has led to deferral or cancellation of many deepwater projects. In such a scenario, the development of new technologies that can access these reservoirs at viable capital investments becomes crucial. It is only with constant development and refinement of new solutions that the oil and gas industry can stay sustainable. This is where we have taken a step towards the future with our subsea technologies like the subsea compression system. How has technology in the oil & gas industry evolved in the last few years & what are the future trends? As an industry, we are at a turning point. We need to reassess the way we work, and invest in research and development to create innovative and costefficient solutions for our clients. At the same time we must also focus on standardization and effectively utilization of already existing technology. One example of the first is the Aker Solutions subsea compression technology, which is opening up new opportunities in deeper waters, harsh environments and in areas far from shore. Subsea compression has a long list of merits: it provides a better business case by cutting costs and increasing production, it is safer, being remotely operated, and minimizes the environmental footprint. We delivered the world’s first subsea compression system for the Åsgard field in Norway in 2015. However, we believe that it’s not just technology that makes a difference to enterprises, but the business models being used. Aker Solutions believes that clients must have access to the best talent across all our offices around the world. For instance, we have teams in Oslo, London, and Mumbai, which ensures faster and more cost-efficient solutions on the Johan Sverdrup mega-project for Statoil. How do you see the Indian scenario in offshore and deepwater oil & gas developments? India needs to significantly reduce its dependence on energy imports. This puts a major focus on developing our hydrocarbon assets wherever discoveries have been made. The development of deepwater fields on the east coast of India offers a great opportunity for the country in the current market scenario. The services and hardware supplies are available at a competitive pricing to help oil companies make investment decisions. It is important to build local expertise in these areas to support the development and reduce dependence on external expertise. The government’s Make in India campaign is addressing some of these issues. However, to ensure that we continue to attract the best technologies and players, the policies for this sector should also be consistent with internationally accepted norms

Offshore World | 7 | April-May 2016

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NEWS FEATURES

MOVING TOWARDS RECOVERY Cairn India’s Rajasthan blocks comprise of Mangala, Bhagyam, Aishwariya and Raageshwari oil and gas fields, which accounted for ~23 per cent of India’s domestic crude production in FY2015. The company has adopted the Enhanced Oil Recovery (EOR) program for long term production from the blocks. In the backdrop of numerous reforms announced by the government on future contractual model, gas prices and license extension in the Indian hydrocarbon sector based on the recommendations of Cabinet Committee on Economic Affairs (CCEA), the article details on how these reforms will help to fast-track development of the Indian hydrocarbon industry and garner investor trust, and shares Cairn India’s typical EOR program implemented in Rajasthan blocks.

imes for the Indian oil and gas sector seem to be changing. First, with the Finance Ministry’s announcement to calculate cess at a 20 per cent ad valorem, as opposed to the earlier punitive system of a fixed rate of cess, things seems to be looking up for the industry. Following which, based on the Cabinet Committee on Economic Affairs’ (CCEA) announcement on future contractual model, gas prices and license extension, the government’s announcement has been a bold and decisive one. Numerous reforms have been introduced by the GoI which highlight the intent of the government towards ensuring energy security. Allowing access to all forms of hydrocarbons, marketing and pricing freedom for gas and moving towards an open acreage licensing system are directionally right steps. These will help to fast-track development, hence, extension of such reforms to other difficult fields including more complex geological formations like Tight Oil, Tight Gas and Enhanced Oil Recovery (EoR) projects would be a strong facilitator in garnering investor trust, leading to enhanced production, ushering India towards energy security. In addition, the License extension policy for 28 discovered fields has brought in a wave of relief for existing investors since it brings predictability and clarity on future producing blocks. This has left private players like Cairn India in anticipation of early resolution of the production-sharing contract (PSC) of the Rajasthan block. The Cairn India-operated Barmer basin in Rajasthan is part of the initial Pre-NELP blocks that are coming up for renewal, the current PSC for the Rajasthan block being valid till May 2020. Cairn India is currently working to monetise the natural gas potential in the Rajasthan block. Cairn India’s Rajasthan block accounted for ~23 per cent of India’s domestic crude production in FY2015. The block’s key assets are the Mangala, Bhagyam, Aishwariya and Raageshwari oil and gas fields. Since the first barrel produced in 2009, the block has delivered more than 300 million barrels to the nation and provided the company with an opportunity to put Rajasthan on the global oil and gas map. The Rajasthan block crossed a cumulative production of 300 million barrels of oil equivalent (mmboe) in the second quarter of 2015, with a total production of 312 mmboe by the end of the quarter. The average facility uptime for the quarter was ~97 per cent.

Leveraging the latest technologies has been the prime mover behind Cairn’s being able to unlock the potential of the Rajasthan block. To sustain the long term production and enhance recovery from the Rajasthan block, Cairn India has adopted the EOR program. The Rajasthan block being the largest EOR project, screening studies by reputable international consultants suggested that aqueous-based chemical flooding EOR processes are the most suitable, based on the Mangala rock and fluid characteristics. The Need The importance of EOR for the Mangala field (and subsequently for Bhagyam and Aishwariya) was realised soon after its discovery in 2004. The field is expected to produce around 35 per cent of the stock tank oil initially in place (STOIIP) over thirty years of conventional water flood operations. In part, due to its moderate oil viscosity, this oil production will be accompanied by large volumes of associated water production, as the less viscous injected water tends to ‘finger’ or channel through the oil, arriving at the production wells prematurely. Because of this, under conventional water flooding, the field can be expected to show moderate to steep oil production decline once it comes off its maximum production plateau. Polymer flood or addition of polymers to water, used particularly in older and declining oil wells and reservoirs, enables better displacement of oil and improves the recovery factor. A full-field polymer flood, among the largest EOR projects in the world, is currently under implementation at Mangala. Cairn India is in the process of ramping up polymer injection in Mangala. The company’s Central Polymer Facility (CPF) will, by the end of the current fiscal, cover the entire Mangala field, Barmer. Current polymer injection rates and production performance have reduced risks significantly, from both the perspective of surface facilities and reservoir. Some of the pre-producer wells have already been converted into polymer injection wells and modifications to the existing facilities for handling polymerised fluids are nearing completion. Once fully operational, the EOR project is expected to improve recovery from the field and arrest the decline in production. Decoding EOR EOR is a term for special techniques to increase the amount of crude oil that can be extracted from a field, over and above conventional primary

Offshore World | 9 | April-May 2016

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NEWS FEATURES depletion or basic water flooding which typically will recover 20-40 per cent of STOIIP. Using typical EOR methods, an additional 10-20 per cent of STOIIP can be extracted from a field. For example, polymers can be used to increase the viscosity of injected water, forcing it to move into regions of the reservoir that would not be contacted by plain water; resulting in a more efficient flood and sweeping more oil to the producers. And this is exactly how Cairn has leverage the technology of EOR. The successful polymer flood pilot in Mangala has produced incremental oil of nearly 11 per cent in the pilot. The company’s CPF is amongst the largest centralised polymer injection facilities in the world and will cover the entire Mangala field by end of FY16. The Results At Mangala, injection has been increased from 80,000 barrels of polymer solution per day in Q1 FY16 to 200,000 polymer solution per day in Q2 FY16. The injection ramp-up plan is on track and the impact of polymer injection on production has been seen, quite in line with the company’s expectations. Current polymer injection rates and production performance have reduced the risks significantly, from both the perspective of surface facilities and reservoir. Cairn expects to ramp up the polymer injection volumes to 400,000 blpd by end of FY16, right on schedule. More than 75 per cent of new wells are already drilled, and work on drilling and surface facilities is headed on schedule. Modifications to the existing facilities for handling polymerised fluids are nearing completion. Some of the pre-producer wells have also been converted into polymer injection wells as per the plan, which will eventually lead to a ramp-up in production. Similarly at the Bhagyam EOR, the Front End Engineering Design contract has been awarded and it is at an advanced stage. Tendering for rig, drilling and completion long lead items has also started while FDP approval is awaited from the JV partner. An additional recovery of ~40-50 mm barrels of unswept oil still in-ground at the Bhagyam field is expected. The company has estimated a capital cost for the Bhagyam EOR project at ~USD 260 million, resulting in a development cost of ~USD 5-6/bbl. Cairn India’s tryst with the best of technologies and the lowest capexes in the world, has defined the company’s character of business since the very beginning. This has had an immense bearing on the company’s profitability and financial resilience. As Mayank Ashar, CEO and Managing Director, Cairn India says, “Less than 10 per cent of energy companies in the world can be cash positive in this kind of an economic environment.” Undoubtedly, Cairn’s big reality is its role in achieving energy self-sufficiency for India.

Dear Readers, Offshore World (OSW), a bimonthly publication of Jasubhai Media & CHEMTECH Foundation, disseminates into the entire hydrocarbon industry from upstream to midstream to downstream. The endeavour of OSW is to become a vehicle in making “Hydrocarbon Vision 2025” a reality in terms of technologies, markets and new directions, and to stand as a medium of reflection of the achievements and aspirations of Indian hydrocarbon industry. OSW, the niche bi-monthly publication, covers insights into Exploration & Production, EPC/M in Oil & Gas Industry, Hydrocarbon Infrastructure viz; Oil & Gas Logistics, Transportation and Pipelines; Hydrocarbon Processing & Refining; Natural Gas and LNG through articles and features by industry Leaders and Dignitaries. The publication also carries inputs and views of Policy & Regulations; latest trends and technology from Policy Makers and Experts from Hydrocarbon Industry. You can share technical articles, case studies, and product write-ups in OSW. • Article length should around 1500-2000 words, along with maximum three illustrations, images, graphs, charts, etc. • All images should high resolution (300 DPI) and attached separately in JPEG or JPG format. • Product write-up length should be around 150-200 words, along with image of the product and contact details. Have a look at Editorial calnder of OSW - www.oswindia.com To know more about Chemtech Foundation, Jasubhai Media and other publication and events, please our website – www.chemtech-online.com Thank you, Regards, Rakesh Roy ( Features Writer) Jasubhai Media Pvt Ltd Tel: +91 22 4037 3636 ( Dir: 40373678) | E-mail: rakesh_roy@jasubhai.com

Courtesy: Cairn India www.oswindia.com

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INTERVIEW

â&#x20AC;&#x2DC;Indian petroleum market growth is encouragingâ&#x20AC;&#x2122;

Bharat Oman Refineries Limited (BORL), the joint venture company of Bharat Petroleum Corporation Limited (BPCL) and Oman Oil Company SAOC, Sultanate of Oman (OOC), is augmenting its refining capacity from 6.0 MMTPA to 7.8 MMTPA in next three years. In the backdrop of this development, Mr K Ravi, Chief Operating Officer, Bharat Oman Refineries Limited, elucidated the detail expansion plan in line with the implementation of Euro VI fuel emission standard by 2020 and changing business environment of the Indian refining sector, in an interaction with Rakesh Roy.

India imports more than 80 per cent of crude requirements from oil producing countries and therefore fluctuations in oil prices are being tracked more closely in the domestic markets

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Offshore World | 12 | April-May 2016

INTERVIEW Can you please detail about the capacity expansion plan of BORL from existing capacity of 6 MMT to 7.8 MMTPA in next three years? BORL is augmenting its refining capacity from 6.0 MMTPA to 7.8 MMTPA through low cost refinery debottlenecking project. This will increase the refining capacity by 30 per cent with low capital investment and in line to meet requirement of Auto Fuel Vision & Policy 2025. The project is scheduled to be completed by 2018-19. How do you evaluate the current Indian refinery sector and its growth drivers? Indian petroleum market growth is encouraging and all petroleum products have registered growth except Kerosene. The changing economics of oil and narrowing price gap between diesel and petrol has resulted in a shift again towards petrol driven vehicles. More usage of personal vehicle compared to public transport will boost the demand of transportation fuel. Hence these factors would encourage refining sector.

As crude oil continues its slide, Indian refineries have gained better refining margins. However private refiners score better against their public sector counter parts. India imports more than 80 per cent of crude requirements from oil producing countries and therefore fluctuations in oil prices are being tracked more closely in the domestic markets. Since mid-2014, global crude price have been halved. The purchase term agreements for refiners usually last a year with prices fixed every month on the basis of a formula dependent on the average prices in the international market topped by a premium/discount. In 201415, most refiners were saddled with huge inventory losses due to falling prices that hurt their profits. Spot crude purchase gives flexibility in terms of the types of crude a refiner want to purchase, depending on the demand of the products and refinery configuration. Private refiners procure more crude from spot market based on their refinery configuration and negotiations available at that time. However Indian

BORL would be able to supply 100 per cent Euro IV fuel from April 2017. Once the debottlenecking is complete BORL would be able to supply Euro VI fuel.

Government is also looking into setting up a trading desk for PSU’s which will also give them edge. With the changing business environment, refiners have switched to cheaper crude, especially heavy oil and contain high sulphur to keep higher refining margins. How have Indian refiners, especially BORL, upgraded refining configuration & processing capability of such crudes? BORL is designed to process 100 per cent high sulphur crude processing and some of other refineries are also switching over to process heavier crudes by way of revamp/ modernisation. Government has proposed to implement Euro VI by 2020 by skipping Euro V altogether. How is BORL gearing up in technology & refinery upgradation and funding to match the emission norms in definite time frame? Government proposal of direct switch over from Euro IV to Euro VI grade fuel is a great challenge for all refiners. BORL would be able to supply 100 per cent Euro IV fuel from April 2017. Once the debottlenecking is complete BORL would be able to supply Euro VI fuel.

What are the future challenges that Indian Refineries will face in the coming years while complying with stricter environment, regulatory & fuel emission norms with the demand of middle distillates, etc? In line with climate change objectives and environmental legislations, every country is to cut down its Carbon Dioxide emissions and make fossil fuels more environment-friendly. The quality of crude oil imports to India - mainly ‘sour’ - is a challenge as a result of the stringent product quality requirements currently in place. India is also adopting strict measures to increase the quality of fuels which will make them environment friendly. These measures include phasing out lead, reducing benzene in gasoline, cetane improvement of diesel and sulphur reduction. This brings a great challenge for all Indian Refiners to meet Stringent Product quality in cost effective manner. Please brief us future expansion plans of BORL existing units to raise its refining capacity and new units in pipeline? As indicated above BORL is augmenting expansion project with capacity enhancement from 6 MMTPA to 7.8 MMTPA through low cost debottlenecking project Schedule to complete in 2018-19.

Offshore World | 13 | April-May 2016

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FEATURES

FOCUS AREAS IN EPC PROJECTS IN OIL & GAS INDUSTRY – PROJECT MANAGEMENT IN PRACTICE With the low oil prices adding fuel to the Global economic crisis, the competition in the EPC industry is intense with negative impact on the profit margins. The market complexities are compounded with increasing stakeholder’s expectations from EPC companies. It is therefore important that project managers understand the thrust areas in EPC projects of oil and gas industry and identify key success parameters. This article suggests a few measures that project managers can adopt & practice for successful delivery of EPC projects.

PC Project Management in Oil & Gas industry covers Engineering (such as Basic engineering & multi-disciplinary detailed engineering), Procurement, and Construction, Commissioning, performance testing and Start-up. These projects also involve high degree of complex automations and support services to facilitate sustainable and reliable plant operations once commissioned. As many projects are carried out in remote locations under challenging socio-politicaleconomic environments, it is important that the best project management practices are identified, chosen, adopted and effectively implemented. Project Management – “First Time Right” It is a fact that today’s demanding customers not only expect timely completion of the Project, meeting the highest technical, quality and safety standards, but also expect that the project must achieve flawless Start-up as well as ramp up the commissioned unit to its operating capacity in the shortest possible duration. In modern times Project Management in Practice focuses beyond providing EPC project delivery approach with an Integrated EPC Plan. Addressing the challenges faced during execution EPC projects in Oil & Gas industry can set a possible path to successful project completion. Few common challenges faced can be Safety ,Flawless start-up, Risk mitigation ,Preservation of Critical equipment’s, Stores management , Front availability, Ensuring

Many a times, the failures can be attributed to poor engagement of all stakeholders of the project. It is therefore absolutely necessary for an increased and involved engagement of each stake holder at all levels right from the project initiation phase till handing over. This is referred in this article as “first time right approach”. Interestingly, Out of seven projects that were selected only in three projects the criteria of “first time right approach” was satisfied showing 43% of the cases actually meet the success requirement. From the statistics it is seen that there is an increasing awareness of implementing safety throughout the project life cycle.70% of the projects had good safety record while 30% had scope for improvement. Like safety Human factor and trained and skilled manpower is an equally important for project success. Although there is a scope for improvement several socio – economic factors dominate and govern this complex resource allocation. Aligning with the moving trend and technologies, investing in latest tools for efficient and effective project management is an initiative which is driven more by the company culture than the project team. However the Project team can proactively allocate a budget to invest in the latest tools and software’s and show case its effectiveness in project success.

Achieving a Flawless start-up is a dream of every customer which the EPC contractor is expected to fulfil. It is up to the contractor to take initiatives and various steps to move toward a common goal, right from project inception by efficiently and effectively using the Project management techniques.

availability of critical equipment’s, team coordination and inadequate EPC coordination & Alignment . Allocating Trained and Skilled manpower is also found to drive many of these challenges in EPC projects in Oil & Gas industry. The overall performance of few projects that were executed by various contractors in the past, were analysed for a select parameters and the finding discussed in the following Section followed by a case study of successful shutdown project. www.oswindia.com

Offshore World | 14 | April-May 2016

FEATURES Table 1: The table indicates the level of achievement in each of the project. Sl No Success Criteria

First Time right

Partial

Yes

Partial

Safety Compliance

Good

Adequate

Human Factor / Team alignment

Adequate

Good

Poor

Adequate

Adaptability to Modern tools/ Software

Yes

Flawless start-up achieved

Partial

Yes

Partial

Project integration refers to identify, define, combine, unify and coordinate with other processes and project management activities with the process group for managing the stake holderâ&#x20AC;&#x2122;s expectation and project delivery with a better understanding of the scope, risk and constraints associated with the project. This can also help the project team to effectively conduct Value Engineering, Constructability review, Project Safety Analysis and get the Risk Profile that represents the actual project scenario. Within L&T Hydrocarbon Engineering, the concept of Integrated Planning has been successfully implemented to execute five complex and large Oil and Gas projects for Domestic and International clients. The minimum value of the project was above 100 Million USD and a shortest delivery amongst the projects was of 24 months. Case Study Project - Annual Plant Shutdown The case under discussion is Implementation of 2 Shutdowns at a project site in western India. Although the job involved around 45 to 50,000 man-hours spread over 11 days, extensive use of project management techniques could help to efficiently complete each of the two shutdown project. The job involved multiple and critical activities during the plant Annual Shutdown scheduled in peak summer months. The team had only 182 days

to plan and execute the shutdown work, with several long lead supplies. With no precedence of executing such critical activities in a very short duration, there was absolute need for meticulous integrated planning. The team star ted with the preparation of Project char ter as par t of integrated project management plan. Generally project teams use the Char ter in understanding the high level deliverables, justify the project, authorize the project manager to initiate the project, to list assumptions and to identify risks. Only in few cases it is found that the teams make an effor t to identify stakeholders and list success criteria in the char ter. This is attributed to limited time available project teams and in most cases the teams focus more on execution to avoid failures and in the process run the risk of missing success criteria! The team in the case project understood the risk of having a poor project charter and therefore team focused and spent quality time on understanding the customer expectations and clearly identifying those factors that would be considered crucial success criteria for the project. With all the initial assessment done the Initial Estimated Shutdown duration was over 20 Days but the charter outcome reduced it to maximum of 11 -12 days. Figure 1 below shows the a few parts attended during the shutdown.

Figure 1 Offshore World | 15 April-May 2016

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FEATURES The project team also realized that extensive engagement of all the stake holders was the key to make an integrated Plan and roll out a reasonable and realistic schedule. The schedules were created from work packages that were derived using a work breakdown structure.While making the WBS and work package, factoring constructability was given highest priority and allocating additional resources during engineering phase to incorporate features for minimising construction durations.

In the case discussed the Risk Review, Job Safety Analysis, Method statement approach for Execution phase pre and during shutdown helped in successful execution of the shutdown project with in the Shutdown window. This is an example of how successfully shut-down project can be implemented by an effective combination of empowered Project Management Team, collaborative Client and efficient use of Project management techniques led to timely completion of the projects.

Ensuring team buy in while creating work packages and assigning responsibility to team members helped in controlling the project as well. The meticulously worked out time and resource allocation had a bottom up approach bringing in great sense of ownership amongst each stake holder and sense of fulfillment at the end of the shutdown. By preparing a L5 level micro schedule Resources allocation on hourly basis could be achieved. During execution, working 24x7 progress monitoring was done every 3 hours in a 12 hour shift to take corrective actions driving timely completion.

Recommendations With ever increasing size and complexity of EPC projects worldwide, efficient use of Project management techniques has no substitute. As Project Management is a vast subject by itself and we have tried to capture few success criterions which can be explored, adapted, refined, customised and implemented as it may suit.

Extensive planning of shutdown also involved preparation of job cards containing detailed information on time, manpower, equipment, consumables, location of the job, etc. for each activity with the work packs. Presence of customer’s team at engineering centre helped speed up approval and review process and shorten deliveries. Engineering was driven based on front Generation than progress. Modularisation, skidding, pre cast structures, foundations were a few possibilities for reduced construction time at the same time allow flexibility for any site modification or changes. Identifying work packages owners could bring in sense of ownership, accountability, better monitoring & control and timely completion. Identifying Cross functional dependencies called for additional dedicated resources, but the results compensated the efforts. These were some of the good practices adopted in the project. Performing a detailed Risk Reviews helped to mitigate all possible eventualities as there was very little scope for corrective action in case of any major event .In the present case ,two identified events as with very low probability of occurrence, actually occurred which in reality would have created catastrophic impact. The exercise resulted in mitigation of all possible risks that could be envisaged. Having recognised and value the importance of safety, allocating budget and resources for strict implementation of safety norms at every project stage, within the office and residential premises was never a constraint. There was focus on continuous on-site safety training program supported by initiatives and incentives to sensitise project personnel for safe execution.In the given case despite taking special efforts to take precaution at every stage, there was a near miss incident during wee hours of a night shift. The investigation pointed to lower lux level in that area. The motto of ZERO Lost time Incident can be aimed at only by bringing in safety awareness among every level and intensive training of key personnel at specialised institutes like L&T Safety Innovation School. Actually the budget for implementing Job and Human safety was very small as compared to the loss in case of an event. Human factor played an equally important and crucial role in execution of shutdowns where 24x7 working with intense and demanding activities is mandatory. Extending facilities even to workmen in line with International standards and practices was on top of the agenda and another major contributor to successful project. www.oswindia.com

A robust and realistic schedule factoring risk, safety and quality and contractual requirements can give a larger picture for the project manager. Customer’s engagement at engineering centre is crucial as is a detailed constructability study for exploring options to reduce construction time with improved flexibility. Safety : a. Project leaders can recognise and value the impor tance of safety, at ever y project stage, offices and residential premises to allocate sufficient budget. b. Minimum Lost time Incident be aimed at by bringing in continuous awareness amongst the projec t team on the Safet y policies and procedures applicable to the project and ongoing On-site safety training program to ALL. c. Improved ratio of Safety supervisors to workmen (1: 30 to 1:50) is a metric that needs to be adopted and implemented across all EPC projects. d. Training of key personnel at specialised safety training centres such as L&T Safety Innovation School is recommended. Project Controls: a. Factoring constructability of each work package can be given high priority while creating WBS and work package. b. Adopting Front loading approach to engage all stake holders, allocating more engineering resources to minimise construction durations. c. Schedule can be made Robust and realistic by factoring Risk, Safety, Quality, contractual requirements for each work package. d. Project manager can have a larger picture of the project by Identifying Cross functional dependencies requiring additional dedicated resources. Engineering: a. As engineering controls the fate of the Project, value engineering can lay a strong foundations. b. Active participation of Customer team at engineering centre can speed up approvals process and shorter deliveries. c. Participation of client’s operation team during every 3D model review, can bring in points on operational safety to move towards ‘First time right’ and “Flaw less start-up”. d. Given a situation, driving Engineering to create work fronts for Critical activities /equipment’s may be a more preferred option over an overall engineering progress.

Offshore World | 16 | April-May 2016

FEATURES Risk Profiling: a. Proactively and continuously Risk profiling each Work Package throughout the project life cycle is recommended. b. Integrating risk with other Project management function highlight impact of other factors on the project. c. Mitigating risks in the initial project phase can influence project scope, quality, and time and cost positively. d. Risk profiling and mitigation for shutdown jobs is highly recommended. Construction: a. Inputs of a detailed constructability study in the initial project phase can optimise plant layout as well as help explore the possibility of Modularisation, pre cast structures/foundations, heavy lifts etc. b. Pre-fabricated / modularised concept has multiple benefits in reduced construction time and flexibility, for changes as well as reduced project delivery times.

 Very High emphasis on HSE, followed by quality, time and cost.  Project team must appreciate the benefit of aligning towards “First time right”.  Project Manager can actively engage with clients & other stakeholders for understanding their perspectives on Project success criteria.

 The objectives of Project Organization be aligned with the client’s Organization which can reflect in the Project Charter  Integrated Planning Approach can be a good execution strategy with emphasis on safety and Risk.  “Integrated Planning approach“, “First time right” and “Flawless start up” is the need of the time in Oil & Gas Projects to ensure project success.

Conclusion EPC Project Management in Oil & Gas industry demands the best project management Practices and this ar ticle is an attempt to present the common challenges faced in most the projects and an approach to tackle them through a case study approach. The study has resulted in the some insight which can be possible actions for Project managers,

Mr A M Joshi Project Manager L&T Hydrocarbon Engineering Ltd Email: AM.Joshi@larsentoubro.com

Dr Hariharan Subramanyan Faculty, Larsen & Toubro Institute of Project Management Email : hsubramanyan@lntipm.org

NEXT ISSUE FOCUS: Health, Safety and Environments (HSE) Practices & Policies are paramount for the Oil & Gas industry for its association with hazards and risks. The oil and gas sector starts to see some recovery from recent fluctuations in oil prices and HSE and Process Safety Managers are now – more than ever before – searching for solutions to mitigate risks, maintaining safety and adhering to the stricter environmental regulations. The forthcoming June July 2016 issue of Offshore World is based on “HSE in Oil & Gas Industry” and will focus on new industry approaches and technologies that apply in Health Safety and Environment (HSE) risks and process safety management strategies for the entire oil & gas value chain. We have invited industry experts to share their views through Guest Columns, Technical Articles and Industry Case Studies on promising new technologies & innovations across the entire hydrocarbon segments.

HSE IN OIL & GAS INDUSTRY Offshore World | 17 April-May 2016

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FEATURES

POLLUTION CONTROL MEASURES IN REFINERY AND DOWNSTREAM PETROCHEMICAL PLANTS We all are aware that pollution is a global problem that needs no introduction. With increasing population and pollution of surface & ground water sources, the problem is aggravated with each passing day. Indiscriminate industrial development and exploitation of limited water sources are compelling every industry to seriously address the problem. Availability of water itself has become a serious threat. Therefore, industries are considering various options to reduce their water usage and to recycle water to the extent possible, including selection of manufacturing technologies that use minimum water, produce less waste water as well as other solid and liquid waste. As the cost of water increases, legislation becomes more stringent and enforcement stricter making water recycle a viable option. This article discusses the recycle, zero liquid discharge and solid waste management philosophies and explores their various technologies.

revention is better than cure. This also applies to pollution. Prevention or minimisation of pollution at source is the best control method. Hence, before going into the methods of effluent treatment, we should look at the possibilities of preventing or minimising effluent generation. Pollution prevention is defined as the use of materials, processes or practices that reduce or eliminate the generation of pollutants or wastes at the source. Also known as reduction at source, pollution prevention includes practices that reduce the use of hazardous and non-hazardous materials, energy, water or other natural resources. Pollution prevention in the manufacturing industry can be achieved by changing production processes to reduce or eliminate the generation of waste at the source. As it applies to industry, the environmental management hierarchy stipulates that when possible: • Pollution should be reduced at the source • Pollution products that cannot be reduced should be recycled in an environmentally safe manner • Disposal into the environment should be used only as a last resort and should be conducted in an environmentally safe manner Recycle of Waste Water and Study of its Application in Various Industries Waste water recycle should take shape at the drawing board stage in contrast to the conventional treatment approach of designing the raw water and waste water treatment plants (end of pipe solutions) separately. This will enable planning for water recycle at the design stage itself. The benefits are many. Firstly, because water is recycled, raw water consumption reduces. The designer can therefore plan for a raw water treatment plant of lower capacity

Raw Water

Water Treatment Plant

Treated Water

and cost. Secondly, the effluent treatment plant’s capacity is also reduced as we are treating the effluent which is not being recycled and hence the quantity of waste disposed is less, leading to further cost reduction. Investment is certainly required for product recovery, water recycle plants and advanced technologies to handle even higher concentrations of contaminants. However, the life cycle and return on investment is quite attractive. Pollution is not just abated but prevented; pollutants are separated not destroyed; energy is saved and the total cost of water and waste water treatment is reduced. Hence, we can use this experience of on/offsite recycle and integrated solutions for water and waste water treatment in large industries to achieve the goal of ‘Total Water Management’ at the design stage. We need to only apply these approaches in a complex industry in multiple ways. Guidelines for Selection of Recycle Scheme 1. Study the manufacturing process thoroughly and identify areas where reduction of water consumption is possible. 2. Identify the process where reduction of pollution load is possible by changing raw material or adopting cleaner manufacturing process. 3. Proper analysis of various streams especially targeting the contaminants which are process specific. 4. Identify streams that can be segregated and treated economically. For example, in electroplating, the rinsed water can be segregated and treated for recovery of plating metal. This not only reduces the overall

Process

Eﬄuent

Figure 1: Conventional Treatment www.oswindia.com

Offshore World | 18 | April-May 2016

Eﬄuent Treatment Plant

Discharge

FEATURES Reduction at Source

Product Recovery Recovered Product

Raw Water

Water Treatment Plant Recycled Water

Water Reuse

Treated Water

Process

Eﬄuent

Product Recovery Plant

Zero Liquid Discharge Plant

Partially Recovered Eﬄuent

No Liquid Discharge

Waste Minimisation

Figure 2: Modern Integrated Solution

cost of recycle but also facilitates the recovery of valuable products from the waste water stream. 5. Identify effluents which are relatively clean and can be treated with simple processes so that they can be recycled internally without letting the water out into an effluent treatment plant. 6. Identify the quality of water required at various manufacturing stages. For instance, steam generation may require high quality water and washing or cooling water make up may not require high quality water. It is always economical to design a recycle system to produce water suitable for lower end usage. 7. Select a technology that is easy to implement, operate, maintain & service. 8. Look for the availability of spare parts that may be needed in the future. 9. Reliability of performance in the long run is extremely important. 10. Low in operating cost. 11. Good service network of the plant supplier.

Recycle Technologies Any waste water recycling plant requires three stages of treatment as follows: 1. Effluent treatment 2. Tertiary treatment 3. Advanced tertiary treatment 4. Zero liquid discharge Effluent Treatment For a good effluent recycle system, a good effluent treatment is a pre-requisite. Unless we remove the easily removable pollutants with cost-effective methods, it would be difficult to recycle the effluents economically. Usually effluent treatment plants (ETPs) are designed to meet statutory requirements for disposal. When recycling is considered, the ETP should also be designed considering overall requirements of treatment. For example, in India, disposal

Effluent Treatment Technologies (Primary and Secondary) Pollutant

Treatment Technology

Floating matter

Manual bar screens, mechanically cleaned screens, drum screens, etc.

Grit

Manual grit chambers, aerated grit chambers, deaerator, etc.

Oil & grease

Oil & grease traps, API oil separators, TPI oil separators, dissolved air ﬂoatation (DAF) systems, tubular ultra ﬁltration, etc.

Acidity/alkalinity

Neutralisation using acid/alkali dosing

Suspended solids

Clarifiers, clariflocculators, high rate solid contact clarifiers (HRSCC), lamella clarifiers, tube settlers, DAF, ultra high rate clarifiers, pulsating clarifiers, etc.

BOD/COD/NH4/TKN/TP/Phenol/CN/SCN

Biological systems such as activated sludge process, trickling ﬁlters, sequential batch reactors (SBRs), membrane bio-reactors (MBRs), etc.

Heavy metals

Precipitation using solid contact clariﬁers, ion exchange processes, membrane systems for metal recovery, etc.

Toxic substances

Diﬀerent treatment technologies are adopted based on the nature and concentration of toxic substances. For example, phenols can be removed with biological systems at low concentrations whereas chemical oxidation may be required for higher concentrations.

Recalcitrant compounds/COD

Photo-chemical oxidation is used to remove or break recalcitrant and complex organics such as phenols, benzene, pesticides, etc. Offshore World | 19 | April-May 2016

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FEATURES standards do not require complete removal of nutrients and dissolved salts. But, when we are installing a downstream reverse osmosis system, it is better to remove nutrients and dissolved salts in the biological system of the ETP. This will help reduce fouling of the reverse osmosis system. There are different technologies available for effluent treatment to remove different pollutants. The table below lists some generic technologies applied in effluent treatment.

and downstream petrochemical waste water to recover more than 95% of water, or as a part of the zero liquid discharge (ZLD) process. WATER MANAGEMENT IN REFINERY - CASE STUDIES Reliance Industries Limited

Tertiary Treatment Treatment beyond disposal norms for reusing effluents for low end usages is called tertiary treatment. It acts as pretreatment to advanced treatment for complete recycle of effluents. Following table enlists some generic technologies applied in tertiary treatment. Tertiary Treatment Technologies Pollutant

Treatment Technology

Turbidity

Gravity sand filters, pressure sand filters, dual media filters, multi media filters, continuous sand filters, auto valveless filters, etc.

Bacteria

Chlorine dioxide, chlorination, ozonation, ultraviolet sterilisation, mixed oxidant systems, etc.

Colour

Oxidation, precipitation, adsorption, nanoﬁltration, etc.

Residual chlorine

Activated carbon ﬁltration, dosing of reducing agents, ultraviolet treatment, etc.

Advanced Tertiary Treatment Further treatment of secondary treated effluents is required for conforming to the requirements of high end usages (boiler feed, process, etc.) of treated water. Following are some of the technologies available to remove various pollutants in advanced treatment: Advanced Treatment Technologies Pollutant

Treatment Technology

Hardness

Chemical precipitation, ion exchange softeners, nanoﬁltration, etc.

Silica

Chemical precipitation, ion exchange processes, reverse osmosis, etc.

Turbidity, SDI

Sand or multimedia filtration, ultra filtration, microfiltration, etc.

Dissolved solids Reverse osmosis systems, ion exchange processes, electrodialysis, etc. There are various other technologies which are contaminant and end use specific such as fluoride removal. Zero Liquid Discharge Treatment (Evaporation and recovery of waste water containing highly soluble salts) The highly concentrated reject from the process is further treated in multi effect evaporator (MEE) system generally after reducing dissolved salts by RO processes and the advanced tertiary treatment. The MEE process uses either mechanical or thermal vapour compression using forced circulation evaporators, falling film evaporators or in combination. Thus, evaporation is increasingly considered for the treatment of refinery www.oswindia.com

Effluent Treatment Plant at Reliance Industries Ltd., Jamnagar, Gujarat

Reliance Industries Limited (RIL) has enhanced the capacity of the Jamnagar Refinery to 12,00,000 barrels per stream per day (1200 K BPSD) with the commissioning of the Jamnagar Export Refinery Project (JERP) in Gujarat. Waste water treatment is carried out in a dedicated state-of-the-art completely automated and PLC – operated effluent treatment plant supplied by Ion Exchange. The effluent treatment area is designed to contain and treat all internal process/utility waste water and storm/fire water, with the objective of zero discharge from the new refinery complex. The treated water is recycled back as cooling tower make-up and partially used as process water after reverse osmosis treatment to the high total dissolved solids treatment train or guard tanks, as required. Effluents are segregated into four identical waste water streams designed for a treatment capacity of 500 m 3/h each and maximisation of reuse. The scope of treatment also includes three by-product streams generated during the treatment of refinery waste water (skimmed or slop oils, oily sludge and biological sludge). Skimmed oil is chemical and heat treated, with recovered oils transferred back to the refinery for reprocessing. Each of the above streams employs identical equipment for treating effluents, namely: • Free oil removal facilities including pre-deoiler and API separators with continuous oil skimming and sludge removal facilities • Dissolved air floatation (DAF) unit • Two stage biological treatment • Clarification • Dual media filtration • Activated carbon adsorption • Disinfection – with chlorine and chlorine dioxide

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FEATURES For a good effluent recycle system, a good effluent treatment is a pre-requisite. Unless we remove the easily removable pollutants with cost-effective methods, it would be difficult to recycle the effluents economically. T h e e f f l u e n t t re a t m e n t p l a n t i s t re a t i n g 1 0 0 p e r c e n t e f f l u e n t generated by the refiner y since its commissioning in D ecember 2008 and consistently produces treated effluent (pH 6 - 8.5, sulphide < 0.5 ppm, COD < 50 ppm, oil and grease < 5 ppm, phenol < 0.35 ppm) meeting guaranteed parameters for reuse for various applications mentioned earlier. Chennai Petroleum Corporation Limited The ZLD plant for the expansion at Chennai Petroleum Corporation Limited (CPCL) uses advanced membrane processes to reuse water for its process requirement. CPCL, during its expansion, increased the crude refining capacity at Manali by 3 million metric tonnes per annum. As part of this 3 MMTA expansion project, a new effluent treatment plant (ETP-III) treats effluents generated from the refinery project to meet the MINAS standard. With a view to conserving water, a new zero discharge plant (ZDP) was designed and constructed by Ion Exchange. This plant treats the treated water from ETPIII to enable use of the treated water as make up to the demineralisation plant. The capacity of the ZDP is 200 m 3 /h. The plant was commissioned in 2005 and is operated and maintained by Ion Exchange. Indian Synthetic Rubber Limited

Conclusion Waste water recycle and ZLD is mandatory for many industries because of water scarcity, legislation, rising water costs, unreliable water supplies, environmental requirements from buyers in case of exporters, etc. ZLD also gives enormous importance to sludge management (which is not discussed in this paper and which needs separate attention). Apart from these reasons, industries now identify recycle and ZLD as their social responsibility for environmental friendly manufacturing of goods. Many technologies are now available for managing industrial waste water and other waste. It is of utmost importance to involve environment management specialists right from the planning stage of the project so that the best optimum solutions can be developed. Priority should always be given to source reduction and product recovery rather than end of pipe waste water treatment and expensive methods of ZLD. Right technologies should be adopted for recovery and recycle of water from waste water. Final effluents which cannot be recycled should be treated and disposed of in an environmental friendly way. Ion Exchange provides range of cost effective technologies. These match the oil and downstream petrochemicalâ&#x20AC;&#x2122;s needs for efficient liquid waste treatment, recycle of treated water and zero liquid discharge objectives through tailor made solutions. Ion Exchange can provide advice on the right technology solution through water audit of the project/plant.

ISRL - Downstream petrochemical

Another such example of ZLD is for Indian Synthetic Rubber Limited (ISRL). Three streams containing 3000 m 3/d process effluent along with 360 m 3/d cooling tower blow down and 240 m 3/d DM plant effluent are being treated through primary, secondary, tertiary and advanced tertiary treatments. The final reject (from RO) is being treated in thermal MEE, thereby achieving the objective of > 95 per cent water recovery and ZLD. Offshore World | 21 | April-May 2016

Ajay Popat President - Technology, Corporate Marketing and Corporate Diversification Ion Exchange (India) Limited www.oswindia.com

FEATURES

MODULARIZATION OF LIQUEFIED NATURAL GAS FACILITY Modular plants are becoming ‘new normal’ in the LNG industry. With ever increasing demand for energy, the search for oil and gas has widened to deep water, remote and challenging conditions. Also, with recent developments in technology and innovation, processing of natural gas at remote locations is becoming economically viable. Natural gas is known as the cleanest form of energy. Historically, natural gas is in use for years but there has been continuous advancement in the technology and logistics to make the LNG plants more efficient and economically viable. One of technique towards making it possible is modularization. The article discusses about the modularization technique explaining its benefits, approaches, considerations for selection, risks and application to LNG industry.

t is an economic approach to design that applies the principle of ‘divide and rule’. It means that the process is divided in separate modules and optimized to enhance clarity, simplicity, flexibility and allowing work in parallel.

Create Variety: Customize product to provide customer a well fitted product.

A module is an essential and self-contained functional unit relative to the product of which it is part. The module has, relative to a system definition, standardized interfaces and interactions that allow composition of products by combination (Figure 1).

Reduce Complexity: To enable better handling and improve overview. This can be achieved by breaking down in independent units, working in parallel, distributing tasks, better planning.

• Modularity is an attribute of a system related to structure and functionality. A modular structure is a structure consisting of self-contained, functional units (modules) with standardized inter faces and interactions in accordance with a system definition. Replacing one module with another creates a new variant of the product. • Modularization is the activity in which the structuring in modules takes place.

Figure 2 explains the drivers behind Modularization technique which make this technique handy in large industrial applications.

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The technique offers range of benefits as follows: • Significantly lower capital cost requirement (easier financing) with faster construction and faster product to market (earlier revenue stream during development of gas field) • Standardized, ‘off the shelf’ design, proven technology, minimal (re)engineering • Maximized shop fabrication, minimized field construction, ‘plug and play’ concept • Less complex design means simpler plant operation, improved turndown capability and lower maintenance downtime with multiple production modules • Flexibility to incorporate additional modular trains to add capacity to the facility to suit the particular characteristics of a given gas field (deferred investment) • Plant can be dismantled and relocated when a gas field is depleted (reduced investment risk) Modularization Approaches Currently there are two approaches to achieve modularization.

Figure 1: Knowledge Management in Modularization

Figure 2: Basic Drivers behind Modularization

Utilize Similarities: Reuse resources and standardize to reduce risks using well-known solutions, hence, increasing efficiency.

Customized Designs: This approach is largely followed in the industry to suit the project requirements. The module is designed to meet the specifications for the project. As the design is customized, it takes efforts to design, optimize, document, fabricate and train the operator which is linked with the cost and schedule of the project. In this approach, the fabrication and related permission procedures are need to be carried out well in advance to meet the schedule requirement. Standard Designs: As the name suggest, standard modules are used to meet the project requirements. Many of the technology companies have developed standard designs of the module depending upon the widely used technology and capacity requirements. This approach reduces the design man-hours, cost of fabrication and training requirements. However, it requires that decision over the use shall be taken during initial stages of the project when conceptual document such as plot plan layout is developed.

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FEATURES Application of Modularization Concept to LNG Plant Typically, natural gas plants can be categorized as below (Figure 3):

Figure 3: Construction Types of LNG Plant

Stick Built: This is the most common LNG plant construction method. This requires availability of labor at low cost, site suitable for outdoor work, suitable climatic conditions and large site facility. This method enables low cost construction, schedule flexibility and use of large work forces at site. Sites in location such as Middle East region are suitable for stick built due to vast availability of skilled labor at cheap rate. Modular: This is suitable for plants where site is remotely located, climatic conditions are challenging, labor is costly and site preparation work is significant. This method enables reduction in plant foot print, lower onsite man-power cost and reduction of construction area. Remote locations such as Australia use modular type of construction. Barge Concept: This method utilizes a barge to borne and operate process facilities. The purpose of using barge is essentially due to non-availability of sufficient land space. This method also reduces the need of steelwork on site, allows prefabrication of modular components off-site in a convenient dry-dock situation and, most importantly, gives cost savings as well as higher productivity compared with constructing the plant on site. This also reduces plant footprint and used where plant conditions are challenging for site work. Floating LNG: This is offshore LNG plant. This eliminates the need to route the gas onshore to liquefy and storage, thus, eliminating on-shore liquefaction plant and subsea pipe work. These are most suitable for remote locations with difficult access and sensitive environmental areas, where minimum onsite work is required and possibility of having large work force on site is challenging.

Figure 4: Decision Tree for Modular vs Stick Built Design

Barge and FLNG plants are becoming the need of the hour with the need to explore energy in challenging conditions. Modular designs make construction of these plants possible. Selection of Modular Design Figure 4 typically explains the parameters utilized to make a decision on selection of modular design. Factors such as local content also need to be taken into consideration. Requirement of local content may make it difficult to outsource work and may eliminate benefits of modularization. Next, important question arises is how big or small is good enough size for a module. Decision over the size of the module is a key consideration at the early stages of design that requires assessment of range of factors affecting design and construction (Figure 5).

Figure 5: Module Definition

Note: Definition of module may vary depending upon site, fabricator/supplier

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FEATURES Benefits of Modules Depending upon Size

Key Factors: • Larger the modularization more is the construction cost due to additional steel work required to withstand rigors of shipping, additional cost of shipping and transportation of module at site. However, higher cost of modularization is often offset by reduction in labor cost. • Larger the modulacrization, lower is the overall project cost due to lower field construction cost and shorter construction schedule. • Larger modules require bigger fabrication facilities, multiple construction locations which increases complexity of the project. This requires experienced personnel to plan and execute the activities. • For larger modules, engineering design needs to be completed earlier as the delay can potentially impact the schedule. This is also required to avoid rework in fabrication. • Bulk materials needs to be delivered at fabrication site in advance to meet schedule • Large modules require more complex logistics • For remote locations, module size might be constrained by available shipping, haul road limitations and the available capacity of heavy lift and transportation equipment. • Extent of dredging requirements to bring large modules in larger modules can help reduce costs. Risks Associated with Modularization Modularization benefits the project to achieve lower cost and schedule. However, it is essential to identify risk associated with the modularization.

Table 1 discusses the typical risks. Detail assessment of the risks related to particular project may yield additional results. Modularization of LNG Plant Figure 6 shows the typical stages involved in the realization of modular LNG plant. The schedule of the project depends upon number of factors not limited to location of site, size of the project, facilities involved (Onshore/ offshore/Subsea), stakeholders’ requirement, government regulations, environmental regulations. LNG Plant Process Typical blocks involved in the process flow diagram of LNG process can be identified as follows (Figure 7): NGL: Natural Gas Liquids Typically, the type of technologies involved in the process and design requirements are finalized during pre-FEED stage. During FEED stage, detailed module specifications including layout requirements are generated. The procurement of these modules can start at FEED stage itself subject to assessment of risks. Subcontracting, pre-fabrication, module fabrication can start parallel to design phase. Depending upon the project requirement, each module can be customized or standardized designs can be implemented. Use of standardized designs reduces project schedule and lower cost of fabrication. Where lengthy permitting process is involved, the project schedule can be reduced by early start of work at the fabrication site.

Table 1: Risk vs Effect Analysis Risk

Effect

Delay in development of Modularization strategy and plan

Result in increased project schedule time and project cost and in turn delay in production

Delivery of incomplete modules at shipment

Impact on project schedule, rework for fabrication, logistics issues and increase in project cost

Late engineering deliverables or late revisions

Rework at fabrication site, increase in project cost

Late delivery of steel and piping at site

Construction delay, impact on schedule

Late delivery of Instrument, electrical and EHT materials

Construction delay, impact on schedule

Modules delivered late and/or in wrong sequence

Impact on project schedule, construction delays

Shop workload exceeds capacity

Late delivery, may hamper design accuracy

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FEATURES Cost Distribution of Large Modular Plant

NGL: Natural Gas Liquids Figure 7: Natural Gas Plant Process References 1. Arif Habibullah, et al, LNG conceptual design strategies, 88th GPA Annual Convention in San Antonio, TX, March 2009 2. Arthur J Kidnay & William R Parrish, Fundamentals of Natural gas processing, Taylor and Francis Group, ISBN: 978-0-8493-3406-1, 2006 3. Carliss Young Baldwin & Kim B Clark, Design rules: The power of modularity, The MIT Press, ISBN: 0262024667, 1999 4. Jalj, et al, LNG seminar, Murmansk, Russia, 2012 5. Max Nussbaum& Marin Folo, Design Selection of Cameroon LNG project, Gas technology, 2013 6. Richard Brookfield & Jeremy Cooke, LNG engineering firms embrace modular approach to building liquefaction plants, LNG Journal, July 2011 7. Tetsuo YOSHIMOTO, Modularization, Design Optimization, and Design Rationalization: A Case Study of Electronics Products, Annals of Business Administrative Science 8, 75â&#x20AC;&#x201C;90, 2009

Figure 6: Typical Lifecycle of Modularized LNG Plant and Schedule

8. Thomas D. Miller, et al, Defining Modules, Modularity and Modularization-Evolution

To make the process successful, technology supplier/design supplier needs to have maximum collaboration between Owner, Engineer, Procurement, Construction, Project Management and Fabricators.

of the Concept in a Historical Perspective, Proceedings of the 13th IPS Research Seminar, Fuglsoe 1998. 9. Snohvit LNG Export Terminal, Melkoya Island, Norway

Future Trend Few LNG modularization concepts have been applied to-date. However, modularization approaches such as standardizing modules are being developed in order to further reduce costs. The focus on standardizing the modules will also help reduce procurement cycle time, schedule, and operator training time. Offshore World | 25 | April-May 2016

Sushant G Labhasetwar Process Engineering Consultant Email: sush.2005@gmail.com www.oswindia.com

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AN OFFSHORE 48” OIL PIPELINE ‘SUCCESSFULLY’ INSPECTED THROUGH INTERNAL CORROSION DIRECT ASSESSMENT Oil and gas pipelines for transporting crude oil and gas, which are very hazard in nature, are operated through corrosive environments. Thus material decoration and chances of leaks and/or catastrophic ruptures of transmission pipelines are inevitable. Therefore timely inspection and maintenance of pipelines is necessary to avoid these kind situations. However, the non-availability of traps for pigs in pipeline is a major constraint for internal inspection and such lines are called as non-piggable. More than half of the world’s oil and gas pipelines are classified as non-piggable. In the present context, health assessment of non-piggable lines has become a great challenge. The article details on inspection and maintenance of the non-piggable pipelines through Internal Corrosion Direct Assessment (ICDA).

hen pipelines are operated under known or confirmed corrosive environments, material deterioration is inevitable. To prevent potential leaks and/or catastrophic ruptures of transmission pipelines, operators are obligated to assess whether their pipelines can operate under the maximum allowable operating pressure established when they were constructed. In this regard, where pipeline integrity validation options become choices available to the pipeline owner and operator, the NACE (National Association of Corrosion Engineers) International Standard Practice on ‘Direct Assessment’ (DA) provides a reliable integrity validation choice. This ar ticle shall be discussing the attributes of Internal Corrosion Direct Assessment (ICDA) and its successful implementation in the Indian offshore pipeline industr y.

The fact that the technique of DA has been mentioned in the Indian National Pipeline Standards Group and Regulators (OISD – Oil Industr y Safety Directorate) in their Standard 233 for “Guidelines on Inspection of Non-Piggable Pipelines” bolsters the assessment techniques’ credibility. PNGRB (Petroleum and Natural Gas Regulator y Board) has also adopted the ASME (American Society of Mechanical Engineers) B31.8S standard to be mandator y along with the practice of maintaining a complete I nte g r i t y M a n a g e m e nt Sy s te m ( I M S ) . B o t h t h e a b o ve - m e nt i o n e d standards directly refer to the already published NACE DA (ICDA – Dr y Gas, Wet Gas, Liquid Petroleum and the recently released Multi-phase) standards to be an acceptable integrity assessment methodology for non-piggable pipelines. The four-step, continuously iterative DA process requires the integration of data from available line histories, multiple indirect above ground field sur veys for ex ternal defects and internal corrosion predictive modeling (ICPM) for internal, direct examination on the pipe sur face and the subsequent post assessment of the documented results. Typically, the DA process combines both existing and newer techniques for understanding the integrity of a pipeline. www.oswindia.com

The key major advantages of DA over the other available integrity assessment techniques are: • Can locate and predict susceptible areas where defects could form in the future rather than areas where defects have already formed (proactive) • No product interruption is required (non-intrusive) • Mandatory for DA programs to perform the “root cause analysis” for determining the corrosion mechanism. Answers the paramount question asked by operators “Why does the corrosion anomaly exist?” • A need to deliver a go forward plan for the operator (mitigation plan) B a c kg ro u n d f o r D e ve l o p m e n t o f I n te r n a l Co r ro s i o n D i re c t Assessment (ICDA) For years the operators’ inspection and maintenance engineering team were left with two pipeline integrity validation options; hydrostatic pressure testing or ILI (In-line inspection). In many cases the nonavailability of traps for pigs or operational and design constraints in a pipeline restricted the passage for an internal inspection tool classifying such lines as non-piggable. More than half of the world’s oil and gas pipelines are classified as non-piggable. In the present context, health assessment of non-piggable lines has become a great challenge. Few of the reasons why a pipeline could be non-piggable can be illustrated as per the below Figure 1.

*Source: IOCL Noida - PPT on Inspection of Non-piggable Pipelines-Techniques

Offshore World | 26 | April-May 2016

FEATURES Table 1: NACE International DA Standards Threats

DA Process

NACE International Standards

External Corrosion (EC)

External Corrosion Direct Assessment (ECDA)& Confirmatory ECDA (EC-CDA)

ECDA SP-0502-2010 EC-CDA- SP0210-2010

Internal Corrosion (IC)

Internal Corrosion Direct Assessment (ICDA)

Dry Gas - DG-ICDA SP0206-2006 Wet Gas - WG-ICDA SP0110-2010 Liquid Petroleum (crude) LP-ICDA SP0208-2008 Multiphase- MP-ICDA – MP-ICDA SP0116-2016

From a pipeline pigging point of view especially for the Indian environment, all the pipelines regardless of being onshore or offshore can be split into the following five# categories: 1. Piggable lines in which cleaning pigging is carried out 2. Piggable lines in which cleaning pigging has not been performed 3. Piggable lines which are difficult to pig such as prior stuck pig instances etc. 4. Non-piggable pipelines such as well flow lines/ jetty lines/ spur lines etc. 5. SPM / sub-sea lines having no loop # Source: OISD New Delhi Paper – PPT on Inspection of Piggable and Nonpiggable Pipelines To inspect these non-piggable lines, which could be categorized from item 2 to 5 as per above, an option remains of running specialized ILI tools designed specifically for inspection of non-piggable pipelines. The ILI itself is a great tool for finding the existing anomalies in the pipeline; a successful ILI run can provide a complete ‘snap shot’ on the current

condition of the pipeline. But it does not analyze as to where corrosion can occur in the future and why. On the other hand, hydrostatic pressure testing may not be feasible due to non- availability of water and lack of water disposing facility or the criticality of the line that may not allow an operator to interrupt service. A major limitation with hydrostatic testing is that it does not identify any other existing anomaly in the pipeline except the near critical axial flaws that must fail during testing. Post a hydrostatic run, an operator does not get the confidence on the existing pipeline anomalies. Though, hydrostatic pressure testing is considered a great “final” proving tool for assessing the safety of keeping the line in service. B y d e s i g n , D i re c t A s s e s s m e n t i s m e a n t t o b e a n o t h e r i n t e g r i t y assessment technique similar to ILI or hydrostatic pressure testing and is considered just as protective of public safety and the environment a s t h e o t h e r t wo i n s p e c t i o n te c h n i q u e s. E a c h p i p e l i n e i nte g r i t y a s s e s s m e n t m e t h o d c o m p l e m e n t s t h e o t h e r s. Th e y d o n o t h a v e i d e nt i ca l p e r f o r m a n ce, b u t e a c h h a s a dva nt a g e s ove r t h e o t h e r s.

To prevent potential leaks and/or catastrophic ruptures of transmission pipelines, operators are obligated to assess whether their pipelines can operate under the maximum allowable operating pressure established when they were constructed.

The ICDA Program – An offshore pipeline integrity success story: Few basic pipeline details are provided below in Table 2: Table 2: Pipeline Information Pipeline Name Attributes

48” Crude Oil (offshore to onshore)

Year of Commissioning

2006

Nominal Wall Thickness, mm

14.28 & 15.9 for the onshore section of the subject pipeline with 20.6 for offshore

Piggability?

No – as no loop provided. Crawler (tractor) based tethered intelligent pigs can be used

ILI inspection conducted?

No inspection on the oﬀshore section. CP surveys conducted in onshore section from Landfall point to the Tank Farm

Bi-directional?

Line activity?

Periodic as per vessel availability (shut-in under pressure with product when not ﬂowing) Offshore World | 27 April-May 2016

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FEATURES Table 3: Operational Parameters Pipeline Name Attributes

48” Crude Oil (offshore to onshore)

Line Pressure @ inlet

10 Bar

Line Temperature @ inlet

45°C

Flow Rates

Range of 74,980 to 149,125 m3/day

Elevation Profile

Oﬀshore section – data obtained from clients’ latest updated ‘Lateral Displacement Report’

Onshore section – collected by ICDA team

No inspection on the oﬀshore section. CP surveys conducted in onshore section from Landfall point to the Tank Farm

Flow ON / OFF %, monthly

30 – 35% Flow ON from commissioning to Nov-2013.

50-55% Flow ON from Dec-2013 to Current

Periodic as per vessel availability (shut-in under pressure with product when not ﬂowing)

Type and Period of Product

100+ Type of crude oil being imported. The SME’s studied and analyzed all of the 100+ types and concluded to utilize chemical composition for 5** of them. Flow is ON when a vessel berths and the pipeline is shut in with product until the next vessel comes which pushes the product in place. **This is a separate study in itself and ICDA enables an operator to perform What-if scenarios for the diﬀerent types of crude oil being imported

or implementing the ICDA program, the four common steps that were followed for each ICDA project were: 1. Pre Assessment (PrA) 2. Indirect Inspection (IDi) 3. Direct Examination (DEx) 4. Post Assessment (PoA) ICDA Program: Steps 1 & 2 - Pre-Assessment [PrA] & Indirect Inspection [IDi] PrA is the initial step of DA, as defined in the DA standards and requires extensive data collection (both historic and current) to determine the feasibility of the process, define preliminary DA regions within a pipeline and select indirect inspection tools to be used in the implementation of the second step of DA (i.e. indirect surveys - IDi). This ICDA program required detailed discussions with the respective ICDA Subject Matter Experts (SME’s) along with the operator’s team in regards to various product chemistries, volumes, historic operations etc. Some attributes related to historic construction, maintenance, operations, product compositions, corrosion protection and prior investigative excavations were not available for the subject pipeline. Since ICDA was being applied for the first time for the operator, therefore more stringent data collection procedures were adopted during this stage. The operating conditions that were concluded for conducting Internal Corrosion Predictive Modeling (ICPM) as a part of the IDi (second stage of ICDA) are tabulated as per Table 3: The pipeline had gone through a few distinc tive scenarios of operations, since the commissioning time. As more data was collected and assessed during the PrA phase, the different operating regimes became clearer and the line was split into the different scenarios as defined in Table -3. It is VERY impor tant to define EACH of the operating scenarios, as they direc tly affec t the produc t composition, respec tive flow regimes, critical angles and velocities, liquid and solid hold up www.oswindia.com

locations for each of the pipelines. Thereafter, each of the separate s ce n a ri o s n e e d s to u n d e rg o i nte n s e I nte rn a l Co rro s i o n Pre d i c t i o n Modeling (ICPM) and finally the results need to be cumulated for the entire operating histor y of the pipeline. In addition to the above tabulated information – data in regards to gas composition, crude oil composition, O 2 , CO 2 and H 2 O measurements, Water Analysis (for Chlorides, Bicarbonates, Carbonates, Sulfate, Iron, Calcium, Manganese, Sodium, Magnesium, Strontium, Barium, Potassium compositions), Solid Analysis [for type of solid (FeCO 3 , FeS, S 8 , FeO, Mineral Scale, Ni etc.), XRD analysis, SEM analysis], corrosion protection history (inhibitors, chemical programs) and many operational, construction based, material based data were collected for each pipeline under the purview. All of these variables are required as an input for the Internal Corrosion Predictive Modeling (ICPM). Taking the above into consideration, in order to obtain accurate cumulative metal loss %, ICPM was conducted simulating the pipeline flow from the very beginning i.e. from their commissioning years to present. The model to be used needs to very intelligently simulate the operating conditions that the pipeline has actually ‘seen’ during its operating history – and this requires an ICDA SME along with an ICDA team. The ICPM results were plotted in terms of the Elevation, Inclination angle, Pressure, Temperature, Liquid Hold-up, pH, Corrosion Rate, Flow Pattern, Super ficial Liquid Velocity, Superficial Gas Velocity, Liquid Velocity, Gas Velocity, Slug Flow Velocity, Reynolds number for liquid and gas, Gas Density, Gas Viscosity, Oil Density, Oil Viscosity, Partial Pressure for CO2 and H2S, Solids amount, Solids amount deposited etc. - all as a function of chainage. Below Figure 2 illustrates the predicted metal loss % based on the predicted Corrosion Rates obtained from ICPM. I C DA P ro g r a m : S t e p - 3 & 4 D i re c t E x a m i n a t i o n s [ D E x ] a n d Po s t Assessment [PoA]

Offshore World | 28 | April-May 2016

FEATURES Table 4: Predicted Metal Loss% vs. Actual Found at site Site No.

Indirect Inspection (IDi) Direct Examination Stage (Internal Corrosion Predictive Modelling) (DEx) Predicted Vs. Measured (%)

Difference in Wall Loss Predicted Vs. Measured (%)

Internal Corrosion Measured Wall Loss (%) Found ( Yes / No)

Pipeline-3: 48” Crude Oil Pipeline 1

22.45

Yes

27.09

4.64***

15.88

Yes

18.91

3.03

15.89

Yes

21.06

5.17

15.93

Yes

21.06

5.13

15.6

Yes

16.21

0.61

Since the differences between predicted and measured internal corrosion at all investigative locations were within ±10%, the ‘stricter’ rules of WGICDA / MP-ICDA approach used for the subject pipelines was proven to be effective and successful. This was beyond the requirements of the LP-ICDA standard and a path chosen by the ICDA team. CONCLUSION The industry’s need for understanding DA and knowing how it fits in the overall integrity management plan has been given paramount importance. Now the industry has ILI (along with specialized ILI for non-piggable pipelines), hydrostatic pressure testing and DA available as the inspection techniques to optimise their pipeline integrity management programs. All three are complimentary to each other and provide different results for the operator, so that they can assess all pipeline assets.

Figure 2: Predicted Metal Loss% due to the cumulative average corrosion rates with Pitting Factor for the 48” Crude Oil Pipeline

Based on the results of the previous two steps, this stage of ICDA involves selecting multiple excavation locations for evaluating the existing pipeline conditions through detailed NDE scanning. All DEx sites were planned to be of enough length to provide a good sample size of the predicted location. Since the subject pipeline is a combination offshore (≈7Km) to onshore (≈12 Km), excavation was conducted on the onshore segment. The predicted internal corrosion metal loss for all the dig locations versus the actual internal corrosion found is presented under Table 4. ***Highest predicted wall loss matched to the field measured wall loss at dig site It was observed that the maximum discrepancy between the metal loss measured by UT and predicted was 0.61% and 4.64% respectively. Offshore World | 29 April-May 2016

Bidyut B Baniah Project Manager Allied Engineers Email: rbbaniah@alliedengineer.com Ashish Khera, P Eng NACE Instructor – Direct Assessment Allied Engineers Email: akhera@alliedengineer.com www.oswindia.com

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GETTING THE GREEN LIGHT ON THE GREY MATTER Many engineering and construction companies (E&Cs) recognise that helping owner-operators achieve operational excellence is a commercial imperative. Talent and expert skills need to be nurtured as an integral component of their business plan to achieve long-term success. Effective engineering across the asset lifecycle includes making vital operational decisions on a daily basis. With the best people and tools, E&Cs stay efficient and competitive.

weak workforce in a weak economy leaves engineering and construction companies (E&Cs) vulnerable to stronger competition. The key to longterm sustainability in the oil and gas sector is balancing operational strategy with market demand and reliance on the ‘grey matter’. Best-in-class operations require best-in-class minds. Companies need to ensure that their strategies include investment in cutting-edge technologies, brain power and skills to give their businesses a clear advantage in a turbulent marketplace. The current dearth of oil and gas projects is matched by the scarcity of knowledge across key areas of the business. From upstream initiatives through midstream and downstream operational activities, the talent pipeline is the vital ingredient to providing companies with the expertise needed to tackle today’s business challenges. In addition, the platform for tomorrow’s generation of engineers is optimising the big asset – people. Many E&Cs recognise that helping owner-operators achieve operational excellence is no longer an option – it is a commercial imperative. However, for this to happen, it is equally important to see talent and expert skills nurtured as an integral component of their business plan to achieve long-term success. Effective engineering across the asset lifecycle includes making vital operational decisions on a daily basis. Without the best people and tools, it is difficult to remain efficient and competitive. Understanding the Issue The E&C industry is complex and fragmented, covering a range of disciplines, including design and planning, cost estimating, civil engineering, maintenance and refurbishment. The sector employs millions of workers worldwide with varied roles and responsibilities. Many skilled workers are hired by established E&Cs. Yet, they are often only on short-term contracts. This instability means that specialist skills are hard to find. Another barrier to stability is that project bids still tend to be won on a cheapest or fixed price basis, forcing companies to work towards the lowest common denominator. When margins are tight the E&C often faces the biggest risk.

example, involves knowing which projects are forthcoming and having sufficient engineering resources to handle them. At the same time, the ability to demonstrate to clients you can save time, money and maintain quality standards are key to winning contracts and securing client confidence. The big risk is that commercial pressures are forcing E&Cs to take short-term measures, which can damage the skills supply. Talent forced to leave the construction industry today may never return and could migrate to other industries, such as finance and IT. In some cases, veterans with specialist skills are being encouraged to not retire and work part-time to help retain their knowledge and ensure successful project continuity. What the Experts Say Back in 2011, EY Oil & Gas Risk & Opportunity reported, “22 per cent of oil & gas respondents indicated a lack of qualified personnel was already impacting their operations”. However, just four years on and a 2015 Skills & Demand in Industry report by the Institution of Engineering and Technology (IET) reveals that “53 per cent of employers are having difficulty recruiting adequately skilled staff ”. The report also highlights “that almost 70 per cent of employers have reported a lack of available graduates while 66 per cent voiced their concerns that the education system will struggle to keep up with the skills required for technological change”. So, why is industry not learning its lessons? The turbulent economy has clearly forced many E&Cs and owner-operators to cut resources or invest capital elsewhere. However, irrespective of market forces, stronger collaboration between employers and academic institutions is needed to plug gaps and build a sustainable talent pipeline. Ultimately, operational excellence can only be attained with a highly-skilled workforce. Clearly-defined roles and targets are needed in order to control, maintain and sustain the business to short and long-term success.

Recently, E&Cs have reduced staffing levels and consequently lost valuable engineering know-how and experience. A 2014 report by the UK’s Chartered Institute of Building and the Construction Industry Training Board stated, “The downturn in the economy had a devastating effect on construction, with 400,000 job losses and one of the highest redundancy rates of any sector. The impact was particularly felt on recruitment of young people, where apprenticeships have plummeted”. Addressing the pain points of clients efficiently and being able to demonstrate expertise is essential for E&Cs. Tackling capital project uncertainties, for www.oswindia.com

Offshore World | 30 | April-May 2016

FEATURES At a recent European Energy Forum in London, David Brown, CEO, IChemE highlighted: “Skills supply, the human infrastructure of our industries, is not something that you can plan or deal with on a scale of months or years. Like some of the major infrastructure in which we invest, it is something to be planned on a scale more like decades. Enthusing a young person with a career in engineering through to becoming fully qualified, chartered and achieving ‘time to autonomy’ might take up to 15 years”. In view of the cycle time to nurture skills, having the right integrated software tools to help perform effective designs means E&Cs can reach better planning and capital decisions faster. In essence, critical knowledge and skills drive behaviour and dramatically improve results from the plant floor to the boardroom.

Back in 2011, EY Oil & Gas Risk & Opportunity reported, 22 per cent of oil & gas respondents indicated a lack of qualified personnel was already impacting their operations. However, just four years on and a 2015 Skills & Demand in Industry report by the Institution of Engineering and Technology (IET) reveals that 53 per cent of employers are having difficulty recruiting adequately skilled staff. Histor y tells us many companies struggle in a growing market after a slump because they are not ready to compete and fulfil customer demands. Forward thinking E&Cs have decided to redeploy skills to other areas of their business, which ensures they retain the expertise. For example, if the upstream industry sees a downturn and the downstream industry experiences an upturn, smart engineering companies will have safeguarded their skilled workforce to be well placed to competitively ‘bid-to-win’ and successfully fulfil projects. Companies need to be ready and equipped – tooled up and talent rich. The oil and gas industry is asset intensive and needs to be efficiently maintained, so people need continuous improvement through quality training and investment. Invest and Innovate Those E&Cs that have a diverse portfolio supported by expertise and advanced software will capitalise on the opportunities ranging from LNG, exploration and production, power generation, petrochemicals, refining and more. With the increasing use of global project teams, most international E&Cs operate with centres of excellence to attain better business processes, communication and integrated systems.

Thinking Ahead Productivity is a process whereby people, processes and technology can extract the maximum value from a manufacturing asset, which will result in increased E&C performance and profit. As an ageing workforce reaches retirement and diminishing operational expertise takes its toll, retaining talent is a priority. Whilst many E&Cs face a market slump, those companies that do not plan for the market uplift or get the green light to invest in cutting-edge software will suffer from an inability to meet future growth. Operational excellence is not just about physical plant assets – it is also about people. Automating best practice enables more engineers to add value on owner-operator projects. From young engineers to seasoned veterans, technology successfully helps address complex problems that support better decision-making. As smart E&Cs are using their grey matter to invest in software and differentiate their businesses in the market, now is the time to start thinking ahead.

Technology should be seen as a competitive differentiator, not simply a cost of business. Integrated engineering software includes leading products that satisfy an engineer’s needs within every stage of the value chain, such as for conceptual engineering, cost estimation, analysis and understanding the engineering workflow. The results are consistent decisions and improved engineering efficiency delivering benefits of 10-30 per cent in capital and operating costs and 30 per cent in engineering efficiency. In addition, benefits of 2 - 8 per cent in operating cost reduction can be obtained by reusing engineering models during manufacturing and supply chain phases. Offshore World | 31 April-May 2016

Ron Beck Industry Marketing Director AspenTech Email: ron.beck@aspentech.com Sunil Patil Business Consulting Director, APAC AspenTech Email: Sunil.Patil@aspentech.com www.oswindia.com

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CHALLENGES OF UPGRADING DIESEL QUALITY FROM BS III, IV TO BS VI IN INDIA Indian cities are witnessing a rapid increase in air pollution as a result of industrialisation coupled with phenomenal growth of transportation sector. Pollution needs to be controlled from all sources. Vehicular pollution requires stringent controls as vehicles emit toxic fumes within our breathing zone. The following article discusses the need to upgrade diesel quality norms to BS VI and highlights the challenges associated with the technology upgradation.

he transport sector accounts for 70 per cent consumption of diesel in India. Commercial vehicles and public transportation alone account for about 38 per cent diesel consumption. Emission from transportation vehicles is one of the major global concerns having serious impact on public health. To limit health impacts from road transportation, the levels of vehicular emissions shall be drastically curtailed through regulations. India appears among the group of countries with Highest Particulate Matter (PM) levels. Also, its cities have the highest levels of PM10 and PM2.5 when compared to other cities of the world. According to World Health Organisation, 10 out of 20 most polluted cities in the world are in India. Successful reduction of vehicular emissions requires a coordinated implementation of low sulphur fuel and superior vehicle technology. Stringent limits on vehicle emissions will bring technology innovations in automobile industry as well as in refining sector. Vehicle Emission Standards Starting with Supreme Court rulings in the late 1980’s and 1990’s, India began to take the first steps towards mitigating the public health impacts of vehicular emissions. The initial steps consisted of eliminating lead in petrol, switching to Compressed Natural Gas (CNG) for auto rickshaws and buses in Delhi and, subsequently, other cities, and establishing Euro I equivalent emission standards known as India-1 standards for new vehicles. India has since progressively lowered its permissible vehicular pollution emission limits for new four-wheeled vehicles following the path laid out by the European Union by adopting parallel ‘Bharat’ standards. India shifted from Bharat Stage II (BS II) to Bharat stage III (BS III) in 2011 and currently BS III standard (Euro III) has been implemented across the country and Bharat Stage IV (BS IV) in major cities. The Government of India’s Auto Fuel Policy (2003) had envisaged that the Policy undergo periodic revisions to meet the stringent fuel/emission specification requirements. In May 2014 MoP&NG drafted Auto Fuel Policy 2025 which laid a clear roadmap to the year 2025 and also that includes technological and other changes that take place over time in the policy framework. Under this policy, the Expert Committee had recommended that BS IV fuel be required nationwide from April 2017 followed by a further step up to BS V in April 2020 and BS VI in April 2024. Meanwhile in November 2015, a draft notice was published by the Ministry of Road Transport & Highways announcing that BS V would be implemented across the country starting 2019 and BS VI starting 2021. Further the Supreme Court ruling in early January 2016 asked the government to advance the implementation of BS VI emission standards from those contained in the

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November 2015 proposals. The government responded by announcing that they would skip over BS V standards and directly implement BS VI standards for new vehicle models by April 1, 2020 and existing models by April 1, 2021. Policy makers in India are determined to accelerate the implementation of BS VI emission norms by 2020. The Oil Ministry supported this move to proceed directly from BS IV to BS VI, whereas the automotive industry felt it is unrealistic. While the automotive industry was supportive of the dates for BS V, they claimed advancing the dates for BS VI by more than 1 year from those recommended by the Expert Committee would not leave sufficient time for testing and validation of Auto designs. Diesel Quality Requirement Fuel quality plays a very important role in meeting the stringent emission regulations. The fuel used in engines influences their performance and design. Diesel vehicles primarily heavy-duty trucks and buses which account for more than 80 per cent of fine particulates (PM 2.5) and nitrogen oxides (NOx) are prime targets for emission reduction. To the larger extent these pollutants can be reduced by present day available technologies like Diesel Particulate Filters (DPF) for particulates removal and Selective Catalytic Reduction (SCR) for NOx reduction. However, low sulphur fuels ideally less than 10 ppm must be employed to make these technologies function effectively. Hence, BS VI fuels shall be made available by refinery sector in stipulated time frame to implement BS VI emission norms in India. Sulphur is a pollutant itself, but more importantly it interferes with and eventually disables control technologies for all other air pollutants. Sulphur fouls conventional and advanced technologies to control vehicle emissions, including carbon monoxide (CO), par ticulate matter (PM), nitrogen oxides (NOx) and hydrocarbons (HC). Hence low-sulphur fuels are the key to reduce the emissions from existing vehicles and enable advanced control technologies and fuel-efficient designs for new vehicles to function. Challenges Faced by Refinery and Auto Industry We could face two key challenges to implement BS VI norms, firstly the ability of Refining and Marketing companies to quickly upgrade fuel quality from present BS III / IV to BS VI and setting up Pan India fuel supply infrastructure. To achieve reduced Sulphur content in diesel, new process units for Sulphur reduction, hydrogen generation and Sulphur recovery units are to be installed at the refineries. Bigger chunk of investment is, however, required in setting up pan-India BS-VI grade fuel supply.

Offshore World | 32 | April-May 2016

FEATURES The second and more important challenge comes from Auto Sector that requires combustion system developments and lot of design changes in vehicles, to accommodate two critical components - DPF and SCR modules. These latter two technology components are also to be adapted for Indian conditions for vehicles, where running speeds are much lower than in most of the advanced countries. For Heavy duty diesel engines, the key emissions challenges have generally been NOx and Particulate Matter (PM). However, techniques to reduce NOx and PM often lead to an increase in unburned hydrocarbon (HC) and carbon monoxide emissions (CO), which poses additional challenges and can be a limiting factor for particularly NOx emissions, how far it can be reduced. Most efficient way to control the vehicle emissions is by modifying the combustion system using Exhaust Gas Recirculation (EGR), using advanced fuel injection systems with higher pressures and multiple injection, increased flow range turbocharging and model based combustion control using new sensor technology. Other control mechanisms utilise after treatment technologies like SCR where a liquid-reductant agent is injected through a special catalyst into the exhaust stream of a diesel engine and a fuel reformer technology to achieve NOx reductions and DPF to remove diesel particulate matter or soot from the exhaust gas of a diesel engine. The governmentâ&#x20AC;&#x2122;s decision of implementing BS-VI emission norms on new vehicles with effect from April 2020 has drawn concerns from the automotive industry specifically in the areas including rising costs, engine bay design issues, using DPF

vs fuel efficiency trade-off, design time for tailor-made solutions for vehicles sold in India. The optimisation and fitment of these technologies too would take few years. Impact on Refinery Units To produce this BS-VI quality diesel, each refinery shall evaluate their existing configuration and operations. Due to diversified configuration of refineries challenges for upgrading BS-III/IV diesel to BS-VI varies from refinery to refinery. The main diesel streams in a refinery are straight run diesel from Crude Distillation Unit (CDU), diesel produced from hydrocrackers, and Light Cycle Oil (LCO) from fluidised catalytic cracking and cracked gasoil from thermal cracking processes. In order to produce saleable product of BS-VI diesel, refiners shall produce Ultra low sulfur diesel, ULSD (around 6-7 ppm sulfur) in diesel hydrotreaters so that blended diesel with wild diesel streams if any coming from other units can meet 10 ppm sulfur requirement for BS-VI standard. The impact on various units in the refinery complex for augmenting the diesel production from present BS III/ IV specifications to future BS-VI specifications is discussed below. A simplified typical refinery configuration showing the impacted units is given in the Figure 1. Crude Distillation Unit: For producing BS III/IV diesel, refiners have flexibility to rundown straight run diesel to the diesel pool, while to produce BS-VI diesel, refiners will lose this flexibility. To cater to BS VI spec entire straight run diesel from CDU may have to be treated in hydrotreater before sending to diesel pool. This will lead to increase in capacity of existing Hydrotreaters and these plants require revamp for capacity and quality of product.

Figure 1: Simplified typical refinery configuration to show impact of upgrading diesel quality to BS-VI Offshore World | 33 | April-May 2016

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Figure 2: Simplified typical Dht Unit flow diagram showing impact of upgrading diesel quality to Bs-Vi

Hydrocracking Unit: In refineries with hydrocracker configuration, the hydrocracker itself is a source of diesel blending component. The quality of the diesel produced from hydrocrackers is dependent on the operating conditions of the hydrocracker. Typically, the diesel produced from a hydrocracker is superior in quality to straight run production and is lower in sulfur content. In many cases diesel produced from hydrocrackers would not require further treatment even to meet 10 ppm sulfur content. Fluid Catalytic Cracking Unit (FCC): The Light Cycle Oil (LCO), the diesel blending component produced from FCC units is inferior in quality i.e low cetane number, higher polyaromatics, high sulfur content unless the FCC feed has been pre-treated. As diesel specifications have tightened, most refiners have been forced to reduce the amount of LCO which can be blended into diesel pool. Alternatively, refiners can use the LCO as viscosity cutter in heavy fuel oil blending. However, this is not a viable option now as heavy fuel oil demand is reducing constantly. Many refiners therefore making investments to upgrade LCO to low sulphur diesel through diesel hydrotreating units, however it is generally expensive because of their relatively high operating pressure and expensive catalysts. Delayed Coker Unit (DCU): The Diesel produced from thermal cracking process is inferior in quality with respect to sulfur content, flash point, cetane index. DCU diesel requires hydrotreatment before sending to diesel pool. This will lead to increase in severity and capacity of the existing hydrotreater plant and require additional investment. However, alternate technologies can also be used to treat exclusively these DCU diesel and FCC LCO, if it offers saving in capex and opex. www.oswindia.com

Kerosene Hydrotreating Unit: As Kerosene is used as buffer fluid between white products transportation in cross country pipe lines, in post implementation of BS VI scenario it is necessary to hydrotreat kerosene to 10 ppm Sulphur level, so that the diesel and gasoline products are not adulterated with untreated kerosene. Hydrogen Unit: Meeting hydrogen requirement in the Refinery is challenging to the Refiner as more hydrogen is required for revamping of hydrotreating units for all distillates. The existing hydrogen network shall be studied for augmentation of additional hydrogen requirement, before deciding for setting up of new Hydrogen plant. Sulfur Block: The sulphur block in the refinery consists of sour water stripper, amine regeneration, sulphur recovery and sulfur pelletiser units. Acid gas generation in the hydrotreating units will increase due to ULSD production. This will lead to additional loads to these sulfur block units and require either revamp/modification of existing units or addition of new units or both. Utility and Off Sites Facilities: The revamp or new Diesel Hydrotreating units demand additional utilities like power, cooling water, steam etc. refiners shall work out the adequacy check of existing utility systems before deciding augmentation of utility systems to cater to additional demand of utilities. In most of the cases augmentation of power system needs to be carried out. In addition to utility system augmentation, possible revamp/ augmentation of offsite facilities like flare system, diesel blending system etc. is also envisaged.

Offshore World | 34 | April-May 2016

FEATURES Impact on Diesel Hydrotreating Units The most impacted unit in the refinery is the Hydrotreating unit for upgradation of BS-III/BS-IV to BS-VI diesel. Current DHT units operating in India are designed and operated to produce export diesel less than 350 ppm sulphur for BS III and less than 50 ppm sulphur for BS IV. These are now required to produce less than 10 ppm sulfur to meet BS-VI specification. In addition to this, in most of the cases capacity augmentation is required as refiners need to go for entire production of diesel to BS-VI spec. There are many challenges Indian refineries may face to upgrade/revamp existing diesel hydrotreating unit. Few major impacts are discussed and elaborated with simplified typical flow diagram (Figure 2) of DHT unit showing impacted section/equipment. Existing Plant Operating/Design Pressure: Diesel hydrotreating plant producing BS-IV spec, the reactor operating pressure is around 50-75 barg depending on quality of feed processed. To produce BS-VI spec the reactor operating pressure shall be around 90-105 barg. If the existing plant reactor is designed below this pressure, massive changes are foreseen in the revamp of the existing units for producing BS-VI grade diesel. Catalyst: The catalyst plays an important role for producing ultra-low sulphur diesel. Typically, cobalt molybdenum (Co-Mo) or Nickel molybdenum (Ni-Mo) catalyst are used in the hydrotreating process. As Sulphur specification of BSVI diesel is comparatively lower than BS-III/IV diesel, the revamp of the Diesel Hydrotreating plant forecasts a change in catalyst type and quantity. In some revamp cases, the installation of new reactor is envisaged to improve the quality of diesel and to increase the throughput of the unit. Hydrogen Requirement: The additional makeup hydrogen requirement and increase in its supply pressure may call for revamp or augmentation of Make-up gas compressor for Hydrogen. In addition to this as higher partial pressure of hydrogen is required for BS-VI operation, the recycle gas loop including Recycle Gas compressor may undergo revamp and augmentation. However, on advent of new generation catalyst formulations the requirement of gas to oil ratio is reduced. This may facilitate use of existing recycle gas loop equipment and lines without major modification.

Unit Shutdown Duration: The typical turnaround given by refinery for this type of revamp is normally around 30 day’s duration. In some cases, there is a requirement of installing new critical equipment like compressor, reactors, etc. which requires 2-3 months duration for site installation. In such a case, adequate planning is required to start the revamp activities prior to taking shutdown of the plant without compromising safety aspect of the running plant. Economics Investment cost of refinery for upgrading diesel quality to BS-VI grade depends on the existing refinery configuration and its operation. The magnitude of investment could be low if existing refinery configuration is with hydrocracker unit, high pressure diesel hydrotreater and processing low sulphur crude. On other hand huge investments are required if existing refinery configuration is with catalytic cracking unit, low pressure hydrotreater and processing high Sulphur crude. Way Forward World is moving fast to Euro-VI fuel standard and by 2017, it is estimated that most countries, would be using Euro-VI fuel. Most of these countries are fuel and vehicle importing countries and so it could impact our competitiveness if India does not move fast to BS-VI level. As refineries need to undergo revamps, modifications and installations of new units to comply with BS VI Diesel quality requirements, it calls for huge investment to the tune of ` 50000 crores in coming years. Also, around ` 40000 crores investment is required in Auto industry for modifications in engine design and addition of DPF and SCR to meet BS VI emission norms by 2020/2021. With falling crude oil prices it is economical to justify making this investment to upgrade diesel fuel and vehicles to meet BS VI emission norms. Also, it is business necessity to go for this investment to be competitive globally as most countries are shifting to Euro VI vehicles very soon. References: 1. All India Study on Sectoral Demand of Diesel and Petrol – Petroleum Planning and Analysis Cell 2. Auto Fuel Vision & Policy 2025 – Ministry of Petroleum & Natural Gas 3. Ministry of Road Transport & Highways notification 4. ICCT Global Health & Climate Roadmap Series – 2013 5. Emission Standards: India- Diesel Net

Utility Distribution: The revamp of DHT unit may call for few changes in the utility distribution network within the DHT units. Plot Area/Plot Plan: The revamp of diesel hydrotreating plant may require modification/addition of equipment like compressor, reactors, heat exchangers, pumps etc. Accommodating all these modifications and new equipment in the existing plot area will be challenging as normally space is limited in existing units. Time Period for Completing Revamp: As per the recent Indian government notification, BS-IV is to be implemented nationwide by Apr-2017 and BS-VI by Apr-2020. At present, some of the refineries in India are still producing BS-III diesel and some are producing partly BS-IV and partly BS-III. The revamp time available for existing Diesel Hydrotreater plant is about 20 to 24 months to meet the dead line of government notification. As it envisages modification/ordering of critical long lead equipment like compressors, meeting this schedule is a challenging task for refiners. Offshore World | 35 | April-May 2016

Akshay Choudhary Engineer – Process Technip India Limited Email: AKChoudhary@technip.com Nihar Ranjan Beuria Sr Principal Engineer- Process Technip India Limited Email: NRBeuria@technip.com M K E Prasad Advisor-Process and Technology Technip India Limited Email: MKEPrasad@technip.com www.oswindia.com

FEATURES

ENERGY COMMODITIES TURNAROUND TO MOVE UP ENERGY COLUMN (PRICE REVIEW): MARCH - APRIL 2016

Reversing past few months’ trend, energy commodity prices turned around and moved up in the two-month period of March and April 2016. Of energy commodities under review, NYMEX gasoline futures surged the most by about 51 per cent. On the other hand, ICE Rotterdam monthly coal futures prices inched up the least by about 3 per cent.

news report stating that most major oil producers supported a decision to stabilize crude oil production, led NYMEX (CME) crude oil (light sweet) futures to start the month of March at USD 34.4 per barrel, up by 1.9 per cent from previous month’s close. With oil prices then moving up almost across the next two months, the opening day’s low of USD 33.37 eventually emerged as the two month-low. Later, weekly data from the US government revealing a fall in weekly domestic crude oil output helped the rise in oil prices. The report raised expectations that further production declines will help ease the market’s surplus of inventories. Oil prices were further boosted on continued talk of a potential output freeze by major producers’ as well weekly data showing a drop in the number of active US oil-drilling rigs for the 11 th straight week. Meanwhile, the Labor Department of the US showed that the US economy added a more-than-expected 242,000 jobs in February, while the unemployment rate held at 4.9 per cent, fueling hopes of improving oil demand. Barring a brief breather helped by a release of bearish note from Goldman Sachs, highlighting the continuing glut of supplies and casting doubt on the sustainability of a recent run-up and intermittent doubts over potential oil freeze, oil prices continued to move up. Oil prices were helped with International Energy Agency indicating that oil prices might have bottomed on expectations that falling supplies will help alleviate the global glut of crude. Again barring brief blips largely with Iran intending to continue to ramp up its oil production and

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a few weak data from China, oil prices largely continued to move up. Plans for a meeting of major oil producers in following month (April) to discuss limiting output and a dovish US Federal Reserve statement, pressuring the US dollar, continued to help the rise in oil prices. The Federal Reserve projected it would deliver just two rate increases in 2016 versus an earlier forecast for four hikes. However at fag end of the month of March, release of US government data revealing a sixth straight weekly climb in crude oil supplies pushed oil prices down. Further with onset of the month of April, crude oil prices declined as a Saudi prince reportedly said the kingdom will not freeze output without Iran and other major producers doing so. Additionally, firming of US dollar on release of stronger-than-expected US jobs data helped the decline in oil prices. Later, crude oil prices increased after weekly US government data (released on April 6) showed a large and unexpected fall in crude inventories as well as an increase in demand by refineries in US. Barring brief sessions, crude oil prices then generally moved up on expectations that US production will continue to decline, signs of solid underlying demand and some renewed optimism about the US economy. Declines in the number of US rigs drilling for crude as well as data pointing to stronger domestic and Chinese demand also helped rise in oil prices. Later, conjectures that Saudi Arabia and Russia have reached a deal to stabilize production, ahead of a meeting of key oil producers Qatar, and a US government agency, EIA (Energy Information Administration) cutting its forecasts on domestic crude output for this year and next, helped the rally in oil prices.

Offshore World | 36 | April-May 2016

FEATURES

By around mid of the month of April, data showing rise in weekly US oil inventory levels, and market participants going skeptical on the outcome of the meeting among major producers, scheduled to discuss a potential production oil freeze, led to some fall in oil prices. Further, with key producers actually failing to agree on a production cap at a meeting held in Doha, oil prices continued to drop. However, subsequently, news that oil production in Kuwait dropped by more than halve due to a workersâ&#x20AC;&#x2122; strike, kept oil price decline under check. Oil prices then continued to move up on reports of supply outages across the world. Along with oil-worker strike in Kuwait, oil production disruption was reported from Nigeria, Iraq and North Sea. Oil price rise was further supported by expectations that US crude production will continue to decline as well as on weakening of US dollar. As a result, NYMEX crude oil futures registered its two-month high of USD 46.78 on the last trading session of the month. Finally, NYMEX crude oil futures closed the two-month period at USD 45.92, up by 36 per cent in the two-month period. Like crude oil, futures prices of oil derivates such as heating oil and gasoline (both traded on NYMEX-CME platform) also moved up in the two-month period of March-April 2016. While, NYMEX heating oil futures prices moved up by 28 per cent; NYMEX gasoline futures prices surged by 51 per cent. In addition to the fall in crude oil prices, significant drawdown in gasoline stock levels in the US over the two month period helped the rise in gasoline prices. The other major energy commodity, NYMEX natural gas futures prices also moved up by 27 per cent in the two-month period of March-April, with a close at USD 2.178 per mmBtu. In the initial period, rise in demand from US consumers, such as power plants, switching from coal to gas helped gas price rise. Later gas prices rose on hopes that massive spending cuts from producers and demand due to warm weather in US would reduce the supply glut. Weather forecasters predicted an extremely hot US summer that could drive strong air-conditioning demand for gas-fired power plants. At fag-end

of the month, gas-price rise was also helped by an explosion on a major interstate pipeline in the US that curtailed supplies even as a spring chill boosted heating demand. Like other energy commodities, ICE Rotterdam monthly coal futures prices also moved up, by 6.6 per cent in the two-month period of March and April. A rare springtime cold snap that has seen temperatures across the European continent plummet to winter levels pushed up coal demand, driving coal prices up. Additionally, on supply front, Indonesian coal exports were disrupted as some ports blocked ships heading to the Philippines due to safety concerns following a spate of ship hijackings in Filipino waters. Finally in the emission segment, EUA futures traded on the ICE platform surged by 23 per cent in the two-month period, spruced by prices rise across energy commodities. Prices rise was also linked to a French proposal to implement a unilateral carbon floor price as well as news that the European Parliamentâ&#x20AC;&#x2122;s industry committee may push for steeper post-2020 ETS cap cuts. (Authors are Managers with Multi Commodity Exchange of India Ltd., Mumbai. Views expressed here are personal.)

Offshore World | 37 | April-May 2016

Niteen M Jain Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: niteen.jain@mcxindia.com Nazir Ahmed Moulvi Senior Analyst, Department of Research & Strategy Multi Commodity Exchange of India Ltd E-mail: nazir.moulvi@mcxindia.com www.oswindia.com

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FLIR GF320 THERMAL CAMERA OFFERS RELIABLE GAS LEAK DETECTION IN BIOGAS FACILITIES Extensive field testing in recent years has revealed that a majority of biogas facilities in Germany experience methane leaks that pose significant threats to the environment, employee safety, and profits. However, with affordable gas finding technology like the FLIR GF320 thermal imager, there is a growing awareness of the effectiveness of thermal imaging for inspecting facilities and finding hidden gas leaks before they cause significant harm.

REVENTING BIOGAS LEAKS Expanding the use of renewable energy sources has become a major policy issue for Europe countries looking to reduce their dependency on fossil fuels and mitigate the effects of climate change. The production of biogas (methane), in particular, is expected to play a larger role in the next decade. In Germany, for example, bioenergy represents approximately five percent of the country’s current energy production, and the government hopes to double that percentage by 2020, according to official reports. However, methane is a greenhouse gas that can harm the environment if not contained properly during the production process. Biogas producers face strict regulations regarding how they trace, document, fix, and report leaks of volatile gases. The FLIR GF320 thermal imager.

IBS GmbH, headquartered in Bremen, Germany, specializes in gas leak detection and analysis at major biogas facilities. The company recently purchased the FLIR GF320 thermal imager to provide its clients with the highest quality gas detection. IBS GmbH learned about using thermography to detect leakage of organic gasses at a trade fair. “We then had a FLIR representative who is also an experienced consultant and [GF320] user demonstrate the technology for one of our customers,” said Ibeling van Lessen, one of IBS GmbH’s managing directors. The engineer has been using the FLIR GF320 for the past two years, and has examined more than 150 biogas plants to date. The GF320 is part of FLIR’s family of non-contact Gas Detection cameras, which can detect dozens of volatile organic compounds in multiple types of facilities, including oil refineries, petrochemical plants, and gas-fired power stations. CONVENTIONAL GAS DETECTION MEASURES ARE OFTEN IMPRACTICAL The sheer size of Biogas facilities can make detecting gas leaks a real challenge. They include huge pieces of equipment, with hundreds of components that need testing. Conventional gas detection involves using leakage spray and gas sensors, known as “sniffers,” but these methods are time-consuming, especially

in hard-to-reach places. For example, a fermenter roof contains an inner gas membrane, eyelets for submersible mixers, and holes in the tank walls-all of which are difficult to access. As a result, van Lessen was looking for a non-contact method for detecting small leaks from a distance. The FLIR GF320 fit the bill. It was compact and mobile, and can identify small gas leaks from several meters away, and big leaks from hundreds of meters away without requiring equipment be shutdown. “The camera is so compact that it can be easily carried, even when using ladders,” said van Lessen. Escaping gasses appear like smoke on the camera’s LCD viewfinder in real time and can be recorded in the camera for easy archiving. Once a leak is detected from a safe distance, users can move closer and quantify the gas concentration using a secondary method. INTERPRETING GAS LEAK FOOTAGE REQUIRES SKILL The clarity of the GF320’s thermal video is due to FLIR’s integrated and patented image analysis software. However, it does take some interpretive skill to analyze

Offshore World | 39 | April-May 2016

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MARKETING INITIATIVE

Gas leak on the terminal strip of the air-supported roof of a fermenter in the visible light spectrum - and in an infrared image made by the FLIR GF320.

black and white JPEG images of escaping gas, which is why van Lessen found the user training by the specialist company ITEMA GmbH particularly helpful. He received precise instructions from qualified personnel on how to handle and operate the camera. “Some experience in image interpretation is necessary to perform reliable leakage localization and assessment,” said van Lessen. FLIR Tools software also comes in quite handy when producing inspection reports. The software allows for sophisticated documentation and is easy to learn in a short period of time. Found leaks can be marked directly in the image and also recorded as a video sequence inside the program. Based on detailed reports, damaged areas can be subsequently repaired by the customer, and then tested again to confirm the leak is fixed. GF320 ALLOWS FOR MAXIMUM MOBILITY The decision to acquire the FLIR GF320 was relatively easy for IBS GmbH, because the camera has no real competition in terms of compact size and

portability. The GF320 is also less expensive than competing thermal cameras. Finally, the GF320 detects not only methane, but a total of 20 gasses, including butane, propane, and benzene. The GF320 is a versatile tool at each step of the biofuel production process, from the fermentation of agricultural byproduct to the generation of power at combined heat and power (CHP) plants. The GF320 can also detect petrol or diesel fumes, as well as exhaust leaks on the turbocharger. And due to its rugged design, the camera can be used in conjunction with an explosion meter in explosive environments. “Its light weight allows for ergonomic working in any position, and the ease of use rounds off the gas camera’s design,” said van Lessen. CONCLUSION: ADDED VALUE FOR USERS AND CUSTOMERS The key success factors for bioenergy facilities continue to be safety, efficiency and profitability. When carrying out gas detection, it is of vital importance that inspectors obtain as complete a picture as possible of the condition of a given plant. A FLIR infrared camera like the FLIR GF320 is an extremely important tool for tracking down potential gas leaks. The FLIR GF320 has certainly provided significant added value for IBS GmbH and its customers, ensuring optimized operation and safety.

For more information visit FLIR Systems India Pvt. Ltd 1111, D Mall, Netaji Subhash Place, Pitampura, New Delhi – 110034, INDIA Tel: +91-11-4560 3555 | Fax: +91-11-4721 2006 Email : flirindia@flir.com.hk www.flir.com www.oswindia.com

Offshore World | 40 | April-May 2016

MARKETING INITIATIVE

SELF-CONDITIONING FLOW METER SOLVES MEASUREMENT CHALLENGES FOR LNG PROCESSING AND DISTRIBUTION

ith the continuous increase in demand for energy worldwide, the popularity of clean-burning natural gas has grown rapidly over the past decades. Its relatively abundant supply, along with new high efficiency production technologies and its lower carbon dioxide (CO2) emission footprint compared to other energy resources, have all made it a cost-effective, environmental-friendly choice for consumer electric power generation systems and other energy applications.

The liquefaction process takes place in hazardous, space-constrained facilities. LNG processing, transportation, storage and distribution require a flow meter that is rugged, dependable, simple to install and suitable for use in potentially explosive environments. Flow meter technologies with moving parts or those requiring complex installation, or frequent recalibration and other maintenance represent potential safety issues, accuracy problems and added operating costs that burden production and refinery operations.

Over long distances, the safest and most economic method of transporting natural gas is in a liquid state. Plants dedicated to turning raw natural gas into Liquefied Natural Gas (LNG) and later back into gas for distribution are either on-stream, under construction or planned all over the globe. The production, processing, storage, transportation and distribution of Natural Gas all require accurate, repeatable flow measurement.

The Solution Featuring a unique self-conditioning flow technology, the versatile V-Cone Flow Meter from McCrometer offers a lowest-installed cost, low-maintenance and highly reliable measurement solution for challenging hazardous applications in LNG processing, transportation, storage and distribution. The V-Cone Flow Meterâ&#x20AC;&#x2122;s no-moving parts, high-reliability design offers safe, highly stable measurement in explosive environments with 25 years of proven service and the standard global agency approvals required for use worldwide. The advanced V-Cone Flow Meter offers significant installed and operational cost savings in LNG facilities with complex or crowded equipment layouts, where the options for upstream and downstream piping are limited. The V-Cone Flow Meter utilizes a centrally located intrusion that redirects the flow to the outside of the pipe and conditions the flow by reshaping the velocity profile, all but eliminating the need for straight pipe runs. The V-Cone requires straight pipe runs of only 0 to 3 pipe diameters upstream and 0 to 1 pipe diameters downstream. This smaller footprint, requiring up to 70% less straight pipe without being affected by flow disturbing equipment up or down stream, is more compact than any other differential pressure meters.

Figure 1: Liquid Natural Gas tanker at port

The high-pressure, volatile nature of this valuable, but hazardous fluid makes it a challenge to measure in both its gaseous and liquefied state. While there are multiple gas and liquid flow measurement technologies, many of them rely on moving part designs (a potential safety hazard) or fail to measure accurately over a wide turndown range under upset conditions or require long straight runs of pipe upstream and downstream from the location of the meter that are difficult to achieve under the always crowded production and refining environment. The Challenge Converting natural gas to its liquefied LNG state reduces its volume by 600 percent. This reduction in volume facilitates transport by ship, export and distribution. The natural gas is first cooled to -260 oF (-162.2 oC), which condenses the fluid into the liquefied state. Flow is then measured again several times during transportation, storage, re-gasification and distribution through pipelines to the end users.

The V-Cone Flow Meter dramatically reduces installed and operational costs. The cost savings is especially common at both liquefaction and re gasification facilities where large lines enter and exit the plant. Beyond the initial savings by installing much shorter pipe runs, there is an additional energy cost savings that accrues from maintaining the extreme cryogenic temperatures necessary over a much shorter distance. The need for costly pipe insulation also is reduced for the same reasons. The V-Cone Flow meter is a differential pressure (dP) type flow meter. The principle of operation is based on Bernoulliâ&#x20AC;&#x2122;s theory of conservation of energy. In a closed system, as the cross sectional area changes, so must velocity. By placing the cone in the pipe, the cross sectional area is reduced forcing velocity of the fluid to increase. As velocity increases, pressure drops and it is that pressure drop that can be measured and used to determine the fluid flow rate. This system can be used for both liquids and gases, as well as steam in other applications.

Offshore World | 41 | April-May 2016

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MARKETING INITIATIVE

Figure 2: The V-Cone Flow Meter

The difference in pressure is incorporated into a derivation of the Bernoulli equation to determine fluid flow. As the fluid moves past the cone, very short vortices are formed that result in a low amplitude, high-frequency signal optimal for excellent signal stability. The V-Cone maintains ±0.5% accuracy and ±0.1% repeatability over a 10 to 1 turndown and the cone conditions the fluid such that there is relatively low permanent head loss. The low permanent head loss achieved by the V-Cone Flow Meter results from the shape of the cone itself, which minimizes energy losses commonly caused by areas of low flow, cavitation and erratic flows. Each V-Cone Flow Meter is sized to meet desired application requirements and may be specifically designed to have high or low head loss. Regardless, the overall energy consumed by the V-Cone Flow Meter is minimized because of its inherently efficient design characteristics.

Figure 3: Cut-away side view shows the V-Cone flow meter’s V-shaped conical intrusion in the center of the pipe.

The rugged, no moving parts V-Cone Flow Meter measures abrasive, dirty, and particle-laden fluids over a wide range of Reynolds numbers without wear or clogging concerns, resulting in an unprecedented standard 25 year operating life with virtually no need for maintenance. Reynolds numbers are a measure of whether flow is laminar or turbulent. With relatively low maintenance costs, which are an extremely important concern in LNG processing and distribution, the V-Cone Flow Meter helps reduce total operating costs. The turbulent vortices produced by the V-Cone condition the fluid flow to be homogeneously distributed and extremely stable. It is this turbulent flow that actually protects the cone as well as the surrounding pipe. The turbulent flow forms a boundary layer against the pipe wall and cone protecting it from particle impingement which can cause deterioration or buildup on the surfaces. Normal surface deterioration in flow meters, piping, and other equipment occurs as a result of fluid sheer stress. Shear stress creates a problem where there is a solid www.oswindia.com

boundary layer in direct contact with the walls of the pipe. Shear stress occurs in laminar and unstable turbulent flows. The V-Cone’s very stable turbulent flow all but eliminates this shear stress and consequently results in no surface deterioration. Additionally, due to the shape of the cone, there is little chance of cavitation on the backside of the cone to erode the surface. Each V-Cone is calibrated during the manufacturing process and because the design is so robust, there is never a need for regular maintenance or recalibration after installation. Conclusion With its self-conditioning, no-moving parts differential pressure (dP) sensing technology, McCrometer’s V-Cone Flow Meter is now installed in a wide variety of LNG applications all over the world. Hundreds of V-Cone Flow Meters have been installed to measure gas as it flows into liquefaction trains and then from the trains into storage tanks. It has even been used in specialized cryogenic applications where flow was never before measured. The versatile V-Cone® Flow Meter offers a lowest-installed cost, low-maintenance and highly reliable measurement solution for challenging hazardous applications in LNG processing, transportation, storage and distribution. Engineers in the oil and gas industry have relied for over 25 years on the V-Cone Flow Meter to remain accurate in the toughest applications. Its low-maintenance, no-moving-parts design is proven to remain accurate for 25 or more years and all but eliminates the need to shut down production for calibrations, inspections or regular primary element replacement needed for an orifice plate. It saves money by increasing production For more information visit Toshniwal Hyvac Pvt Ltd 267,Kilpauk Garden Road Chennai - 600010 Web : www.toshniwal.net visit www.mccrometer.com or email sales@toshniwal.net

Offshore World | 42 | April-May 2016

Mumbai: Aramco, the Saudi oil giant, plans to invest in India’s petroleum sector. Khalid A Al Falih, Head, Aramco, called on Hounrable Prime Minister of India Narendra Modi and conveyed that the state-owned company considers India as the most preferred destination to invest at a time when the global economy is in a crisis.

Cabinet Empowers PSUs to Develop Own Crude Import Policy New Delhi: The Union Cabinet has approved empowering public sector oil companies to develop their own crude oil import policy for import of crude oil consistent with the guidelines of the Central Vigilance Commission and get them approved by their respective boards, an official statement said.

“Minister Al Falih to PM: Aramco looks to India as its No 1 target for investment,” tweeted Vikas Swarup, Spokesperson, External Affairs Ministry.

The Union Cabinet has approved giving powers to public sector oil companies to develop their own crude oil import policy. “The Cabinet has approved that oil PSUs shall be empowered to evolve their own policies for import of crude oil consistent with the guidelines of the Central Vigilance Commission and get them approved by their respective boards,” an official statement said.

Aramco is Saudi Arabia’s national oil company with crude reserves of about 265 billion barrels which is over 15 per cent of all global oil deposits. The Saudi government plans to sell shares in Aramco and transform the oil giant into an industrial conglomerate. Energy-powerhouse Saudi Arabia is India’s largest crude oil supplier, accounting for about one-fifth of total imports and both sides were of the view that cooperation in the sector should expand.

Ravi Shankar Prasad, Union Minister for Communications and Information Technology, said, “The crude import policy needs to be modified to bring it in tune with current needs. The current market practices for purchase of crude oil on spot basis also need to be adopted to compete effectively in the market. The current policy has certain limitations and restrictions in this regard which has now been done away with.”

India is specifically looking at Saudi investment in ‘high temperature deep sea off shore exploration’ and has opened up the sector for FDI.

Prasad added that the measure will increase the operation and commercial flexibility of oil companies and enable them to adopt the most effective procurement practices for import of crude oil.

Vikas Swarup, Spokesperson, External Affairs Ministry

Hydrocarbon Deposit Found in Mizoram Aizawl: Oil and Natural Gas Corporation (ONGC) has found hydrocarbon (gas) deposits at Meidum area in Mizoram-Assam border Kolasib district, said H Rohluna, Industries Minister, State of Mizoram. He said that the Oil exploration companies have been conducting tests on the gas found while drilling and hydro-fracturing have been conducted to find out whether more deposits were available. As of now, the ONGC predicted that there could be 5,52,674 standard cubic feet (SCF) of gas per day from the Meidum exploration site,” he added. Four oil giants were involved in the oil exploration venture in the state, he said, adding, however, that the Reliance was axed for not undertaking exploration and the Director General of Hydrocarbons would soon float another global tender to choose companies to take up exploration in the southern parts of the state.

NEWS

Aramco to Invest in India

Shell India to Sell Diesel at Market Price Mumbai: Shell India, a diversified international oil company, has now introduced its ‘Shell Diesel’ in the domestic market. The announcement by the company comes against the backdrop of diesel price deregulation. The Shell Diesel with fuel economy formula is available at market price at Shell fuel stations across six states of Maharashtra, Tamil Nadu, Karnataka, Gujarat, Andhra Pradesh and Assam. Shell currently has 82 operational fuel stations in India with 27 outlets in Bengaluru. “The Shell Diesel has been designed to ignite and burn more effectively than standard diesel thereby giving extra miles at no extra cost,” a company release said. Shell prides itself in offering international quality fuel, exact quantity and friendly customer service like free windshield cleaning and under bonnet checks at each of its outlets, it added.

IOCL to Buy Stake in Cuddalore Refinery IOCL to Expand its Gujarat Refinery Ahmedabad: Indian Oil Corporation will spend ` 20,000 crore for brownfield expansion of its Gujarat refinery in upgrading the refinery configuration to jump directly from BS IV to the more stringent BS VI norms for petrol and diesel, said Dharmendra Pradhan, Petroleum Minister. The refinery plans to expand is capacity to 18 million tonnes per annum (MTPA) from the existing 13.7 MTPA. The expansion is expected to be commissioned in 2020. After the expansion, it will become the refinery with largest capacity for the company,” the Union Minister said.

Cuddalore: More than a decade after it declined to take a stake in Nagarjuna Group’s refinery in Tamil Nadu, state-owned Indian Oil Corp (IOC) is looking at buying equity stake in its six million tonnes a year Cuddalore refinery. IOCL has held preliminary discussions on a possible equity stake in the project, highly placed sources said. Nagarjuna Oil Refinery Ltd (NORL) holds 46.78 per cent of the equity share capital of Nagarjuna Oil Corporation (NOCL). Tatas too are a shareholder in the refinery. The six million ton refinery is the first phase of a ` 25,000 crore project that will have an ultimate capacity of 12 million tons.

Offshore World | 43 | April-May 2016

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NEWS India-Iran Accord on Crude Oil Imports, Gas Field Development

Iran’s Minister of Petroleum Bijan Zangeneh (R) and Indian counterpart Dharmendra Pradhan signed agreement in Tehran to boost oil and energy cooperation.

Tehran: In aiming to step up energy partnership post-sanctions period of Iran, India and Iran have signed an agreement that involves crude oil imports, petrochemical complexes and gas fields development besides Delhi making an announcement of USD 20 billion for strategic Chabahar Port complex during ongoing two-day visit of Oil Minister Dharmendra Pradhan to Tehran. During Pradhan’s meeting with Iranian counterpart Bijan Zanganeh, the two ministers signed a cooperation agreement encompassing oil exports, petrochemical operations and gas-field development and also discussed on increasing India’s import of Iranian oil from its current 350,000 barrels a day. A high-level delegation of Indian major oil and energy firms who accompanied the Minister, also evinced interest in Iran’s oil, gas and petrochemical projects, government sources here said.

LNG Price Falls on Revised Pact with Qatar New Delhi: The revision in LNG agreement with Qatar has helped bring down cost of importing natural gas to less than USD 5 per mmBtu from USD 12, Oil Minister Dharmendra Pradhan said. In late-December last year, India got Qatar to agree to slashing gas price by half to match a slump in global energy rates, helping the nation save billions of dollars, as well as get waiver from Rs 120 billion liability for short-lifting of gas. India, which got USD 15 billion of benefits during first 11 years of the term-contract with Qatar beginning 2003 by way of enjoying low gas prices when world energy rates were rising, is currently paying less than USD 5 per million British thermal unit for 7.5 million tons a year of LNG it buys from RasGas of Qatar. “Earlier the prices during 2015 were in excess of USD 12 per mmBtu. The current price applicable under the contract works out to less than USD 5 per mmBtu based on prevailing crude prices,” he said in a written reply to a question in the Lok Sabha. This revision, applicable from January 1, has led to making LNG cheaper for the end consumers, he said. The revised formula will base the price on a three-month average figure of Brent crude oil, replacing a five-year average of a basket of crude imported by Japan, with a rider that PLL buys an additional 1 million tons of LNG annually. Further, Petronet LNG Ltd - the firm that imported LNG from RasGas of Qatar - has executed agreement for additional supply of 1 million tons per annum of LNG for about 12 years with effect from January 1, 2016 at the prevailing market prices, he said.

Govt Committed Supply Euro VI Fuel: Nitin Gadkari New Delhi: Rejecting the claim of Automobile industry body Society of Indian Automobile Manufacturers (SIAM) which had earlier accused that the BS VI fuel norms in the draft is ‘inferior’ to Euro VI norms, Nitin Gadkari, Union Transport Minister said that that government is committed to supplying Euro VI compliant fuel which will be at par with international standards.

Gulf Oil to Expand its Lubricant Business Mumbai: In the back of the opportunity emerging for value-added products driven by the Indian government’s push to cutting down emissions Gulf Oil Corp, the Hinduja Group company, is looking for expanding its lubricant business in India with an investment of ` 150 crore in setting up a plant in Chennai. India recently set a 2020 target to implement BS VI emission standards, advancing its previous plan. “It is amazingly brave and wise of India to accelerate the pace of implementing emission norms. It gives us the possibility to work on products that are more focused on fuel economy,” Frank Rutten, Vice President – International, Gulf Oil International. “The moment the legislation creates the right playing ground, the industry immediately plays into it by offering renewable, fuel efficient products,” he added. “When we talk about the growth rate that Gulf Oil is enjoying in India, it will be necessary to expand the t production capability as the product portfolio is likely to get more t complex. The investment in Chennai allows us to have production infrastructure that would match the upcoming product portfolio for the next 10 years,” he said. www.oswindia.com

Nitin Gadkari, Union Transport Minister

Terming the allegations ‘false’, the minister said petroleum refineries were making a huge investment to supply Euro VI compliant fuel, which will minimise pollution that has become a big problem. He said that I do not agree with Siam. When the same car manufacturer can build cars following the same norms across the globe, then why can’t they build it here? The government is not reconsidering its decision. Earlier, refusing to budge under pressure from auto industry on stricter fuel emission norms, Gadkari has said carmakers must follow the same standards in India that they do elsewhere. In a bid to curb vehicular pollution, the government in January decided to implement stricter emission norms of Bharat Stage (BS) VI from April 1, 2020 by skipping BS-V altogether. At present, BS IV norms are followed in parts of India and by April 1, 2017, the whole of the country is scheduled to be covered under it.

Offshore World | 44 | April-May 2016

Iran Demands on being Paid in Euros instead of Rupee

India Intends to Get Gas at 5/mmbtu: Piyush Goyal

New Delhi: Iran, no longer under sanctions, has ended free shipping of crude oil to India and has terminated a three-year old system of getting paid for half of the oil dues in rupees. The Persian Gulf nation is now insisting on being paid in Euros for the oil it sells to Indian refiners. It also wants refiners like Essar Oil and Mangalore Refinery and Petrochemicals Ltd (MPRL) to clear nearly USD 6.5 billion of past dues in Euros, officials said.

New Delhi: India is exploring gas purchase contracts spanning 10-15 years for power projects at a fixed price of USD 5 per mmbtu, said Piyush Goyel, Union Minster of Power, Coal and Renewable Energy.

Iran had in November 2013 offered free delivery of crude oil to Indian refiners as tough Western sanctions crippled its exports. With shipping lines refusing to transport Iranian crude for fear of being sanctioned, Iran used its shipping line for the delivery and did not charge for transportation. “National Iranian Oil Company (NIOC) has written to Indian firms saying it will no longer be shipping oil for free,” an official said.

Saudi, India Discuss Oil Market Situation Riyadh: In his maiden visit to Saudi Arab, India’s Oil Minister Dharmendra Pradhan and his counterpart Saudi Deputy Oil minister Prince Abdulaziz Bin Salman have discussed the situation in oil markets and further cooperation in oil between the two countries, Saudi state news agency reported. The two officials also discussed cooperation between the two countries in energy as well as boosting India’s purchases of crude oil and oil products, and joint investments. India is one of the countries in which state oil giant Saudi Aramco is looking at in terms of downstream investments. The International Energy Agency (IEA) said India could replace China as the main engine of global demand growth, estimating its demand growth at 300,000 bpd - the strongest ever volume increase.

Iran Demands on being Paid in Euros instead of Rupee New Delhi: Iran, no longer under sanctions, has ended free shipping of crude oil to India and has terminated a three-year old system of getting paid for half of the oil dues in rupees. The Persian Gulf nation is now insisting on being paid in Euros for the oil it sells to Indian refiners. It also wants refiners like Essar Oil and Mangalore Refinery and Petrochemicals Ltd (MPRL) to clear nearly USD 6.5 billion of past dues in Euros, officials said. Iran had in November 2013 offered free delivery of crude oil to Indian refiners as tough Western sanctions crippled its exports. With shipping lines refusing to transport Iranian crude for fear of being sanctioned, Iran used its shipping line for the delivery and did not charge for transportation. “National Iranian Oil Company (NIOC) has written to Indian firms saying it will no longer be shipping oil for free,” an official said.

NEWS

Goyal said with about 28 GW of stranded gas assets, the country is a huge and promising Vikas Swarup, Spokesperson, External market as long as the prices are right. “Given Affairs Ministry the current Baltic index, I believe this is a viable proposition,” the minister said at the sideline of a renewable energy investors round table co-hosted by the Confederation of Indian Industry and the US India Business Council in New York. Goyal projected India’s growth to be in double digits by next year, the caveat being that the country needs to get a strong monsoon. The country is open to help power sector investors hedge risk by linking the debt to a basket of currencies or exploring inflation linked tariffs,” he said. During his visit to the UK and the US, the minister discussed the need for a stable and simplified policy and regulatory regime, standardised power purchase contracts and equipment standardisation with the investors.

RIL Lookin at Long-term Oil Supplies from Iran Mumbai: Reliance Industries Ltd, India’s biggest oil refiner, said it is looking to buy more crude from Iran as the company seeks to rebuild ties to benefit from shorter shipping distances. The company had made small purchases from Iran in the current quarter and was currently engaged in talks for bigger supplies, indicating that it could also get into a long-term supply contract, said V Srikanth, Joint Chief Financial Officer, RIL. “We have had engagements with Iran before the sanctions and they have grades of crude that are attractive to us from where we are,” he added.

Govt to Auction Marginal Fields New Delhi: The government is planning to begin the process to auction 46 marginal oil and gas fields in a month after delaying it for several months due to lower oil prices, holding about ` 70,000 crore worth of hydrocarbon reserves that were given-up by state-owned ONGC and Oil India. The auction, to be conducted on simpler contractual terms together with pricing and marketing freedom, will be the first licensing round in over four years. Domestic and international roadshows for the auction will begin on June 6 and e-bidding will start on July 15 and close on October 31. Bids will be finalised by mid-November and contracts signed by January, said Oil Minister Dharmendra Pradhan. Pradhan said the 46 fields that are offered are actually 67 small and marginal discoveries that have been clubbed.

Offshore World | 45 | April-May 2016

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NEWS ONGC to Drill Shale Gas Wells

India’s Fuel Demand to Rise 7.3% in FY17

Mumbai: State-owned ONGC Limited is planning to explore as many as 17 shale gas and oil wells in both east and west coasts with an investment of around Rs 700 crore.

New Delhi: After registering the fastest pace of growth in 15 years, India’s fuel demand is likely to rise by 7.3 per cent in 2016-17 fiscal, lead by robust expansion in consumption of petrol and diesel.

According to the minutes of a recent meeting of the Expert Appraisal Committee (EAC) of Ministry of Environment and Forests, the PSU sought the ministry’s nod to prepare Terms of Reference for exploring the wells.

Fuel consumption, which rose 10.9 per cent in 2015-16 to 183.5 million tonnes, is projected to rise to 190.03 million tonnes, according to demand estimates made by Oil Ministry. Diesel demand, which soared 7.5 per cent to 74.6 million tonnes last fiscal, is projected to further go up by 7.7 per cent to 78.11 million tonnes.

A senior official of the PSU said this is the first time that the oil and gas company has taken up shale gas exploration in such a big scale. Also, it first time that it has taken up shale gas exploration in the Krishna-Godavari basin. “ONGC Ltd has proposed for exploratory drilling of 11 wells for shale oil/ shale gas in Cambay basin at Mehsana, Ahmedabad, Bharuch in Gujarat. Total cost of project is Rs 366 crores,” according to the minutes of the meeting.

Green Nod for LPG Project in West Bengal Kolkata: State-owned fuel retailer BPCL has got green nod for its Rs 694-crore project of developing LPG import terminal as well as storage, bottling and bulk distribution facilities at Haldia Dock Complex in West Bengal. At present, domestic production of LPG is around 12.38 million metric tonne per annum (mmtpa), much lower than the estimated demand of 18.65 mmtpa for this year. The proposed project aims to boost supply and help achieve the government’s target of making LPG available to each household by 2018. As per the proposal, Bharat Petroleum Corporation (BPCL) will set up an import terminal at Haldia to import 1 mmtpa of refrigerated Propane and Butane and transfer it through 7.5-km long twin transfer pipeline for LPG production, despatch of bulk LPG via road tankers and bottling of LPG in cylinder.

The consumption of petrol is projected to rise by 12.4 per cent to 24.14 million tonnes. Petrol consumption was up 14.5 per cent at 21.8 million tonnes in 2015-16, its highest level in two decades as automobile sales grew at their fastest pace in five years on narrowing price differential between petrol and diesel.

Nagarjuna Oil to Revive its Refinery Chennai: Nagarjuna Oil Corporation, which is setting up a refinery in Tamil Nadu, has initiated talks with the royal family of Saudi Arabia for a possible strategic investment as it attempts to complete the project that has been held up for over four years now. In addition, public sector oil companies, led by Indian Oil, are also being nudged by the government to look at possible equity investment. Prime Minister Narendra Modi as well as petroleum minister Dharmendra Pradhan recently visited Saudi Arabia and oil was clearly the main item on the agenda. The Nagarjuna Oil refinery, which will have an annual capacity of six million tonnes in the first phase, is nearly 60 per cent complete but has been held up since a cyclone hit Cuddalore in December 2011. It has been identified as one of the projects that the PMO is pushing for completion.

India to Gradually Move to Gas-based Economy: OilMin

GMR to Set up LNG terminal at Kakinada Port Kakinada: GMR Group is in the process of setting up an LNG (liquefied natural gas) terminal at Andhra Pradesh’s Kakinada sea port with an investment of Rs 471 crore. According to minutes of the meeting held by Expert Appraisal Committee (EAC) under the Ministry of Environment and Forests, the project envisages a start-up capacity of 1.75 million tonnes per annum (MTPA) which comprises of captive use by GMR Energy Limited to the tune of 0.85 MTPA, with the balance for domestic piped and non-piped users within a radius of 450 kms. “The proposed LNG facility consists of the following...development of necessary facility/ equipment for ship berthing and mooring, LNG unloading arms with all safety measures, LNG storage and transportation, onshore insulated cryogenic pipeline, LNG regasification facility and pipeline for connectivity to existing gas distribution grid,” the EAC said. www.oswindia.com

Dharmendra Pradhan, Union Petroleum Minister

New Delhi: India plans to shift to a gas-based economy by boosting domestic production and buying cheap liquefied natural gas (LNG) as the world’s third-biggest oil importer seeks to curb its greenhouse emissions, said Dharmendra Pradhan, Minister of State for Petroleum and Natural Gas, GoI. Gas accounts for about 8 per cent of India’s energy mix, while oil accounts for more than a quarter.

India’s gas supply deficit is expected to widen from 78 million cubic metres a day (mscmd) this fiscal year to 117 mscmd in 2021-22, according to a government estimate. India recently negotiated better terms for a long-term LNG deal with Qatar and importer Petronet LNG is in talks with Exxon to renegotiate pricing for gas from Australia’s Gorgon project.

Offshore World | 46 | April-May 2016

Oil Supply Grows in India, Falls at Global Level: IEA

Green Nod for Exploratory Drilling in TN

New Delhi: A global oil glut that has sent prices tumbling is set to ‘shrink dramatically’ later this year, as wildfires have disrupted Canada’s output and demand in India soars, said the International Energy Agency ( IEA ).

Chennai: The Centre’s green panel has given its nod to RIL for carrying out eight additional exploratory well drilling to ascertain reservoir capacity and commercial viability of hydrocarbons in the block CY-III-D5 in Bay of Bengal off the coast of Tamil Nadu.

Demand for oil worldwide is set to grow at a ‘solid’ rate in 2016, with India as the ‘star performer’, the 29-nation IEA said in its monthly report, adding to it they believed “the global supply surplus of oil will shrink dramatically later this year.” “This provides further support for the argument that India is taking over from China as the main growth market for oil,” the 29-nation IEA said in its monthly report.

Shell India Appoints Nitin Prasad as New Chairman Mumbai: Yasmine Hilton, currently chairman of Shell Companies in India, will end her assignment on 30 September 2016, after 37 years with Shell. Nitin Prasad, Country Head of Shell Lubricants, will succeed Hilton effective 1 October 2016. Hilton began her career in Shell in 1979 in IT and went on to hold a number of senior posts in the Group including chief information officer for the UK and for Shell’s global retail business, operating in all five continents. In October 2012 she took up a four-year assignment as country chairman, the first woman leader in the Indian oil and gas industry. Nitin Prasad, Country Head, Shell Lubricants

Prasad is an electrical engineer from Georgia Institute of Technology, USA and a management graduate from INSEAD. He took up his current appointment in 2011 as general manager, Shell Lubricants, in the third largest lubricants market in the world. His previous roles in Shell include chemicals where he was general manager APME supply chain, and senior advisor on downstream strategy.

Govt to Ink Gas Deals with Gulf for Gas-based Power Projects New Delhi: In a bid to fuel stranded gas based power projects the government is negotiating long term contracts with leading gas suppliers in the Gulf region. The plan is to enter into contracts for importing 70-80 million metric standard cubic metres (mmscmd) of natural gas through long-term contracts of 10-15 years and at affordable rates. Given the price sensitivity of fueling a power project, the government wants these long term contracts in the price range of USD 5 per million British thermal unit (mmBtu). “Similar long term contracts are being negotiated that will enable India to operate its idle gas-based power capacity” says an official in the know of the matter. The source further explained that the government is unlikely to pay anything more than USD 5 per unit of gas, keeping the global slide in prices in mind. Top sources say that discussions with Oman and Iran are already underway.

NEWS

Reliance Industries has been awarded exploratory rights for hydrocarbons prospecting in the offshore block DY-III-D5 under the New Exploration Licensing Policy-III. RIL has already been given the environment clearance to drill 11 exploratory wells in this block. As on date, the company has drilled nine wells and discovered hydrocarbons in three wells. Since seismic data and the drilling campaign shows presence of hydrocarbons in the block, RIL is planning to carry out eight additional exploratory well drilling to establish the reservoir capacity in this block. “In a recent meeting, the Expert Appraisal Committee of the Environment Ministry examined the proposal. After detailed deliberations, the committee recommended the project for environment clearance,” a senior government official said.

New DGH Promises Level Playing Field for E&P Players New Delhi: With contractual disputes dampening India’s efforts to step up investment in its oil and gas hunt, the new DGH Atanu Chakraborty has promised to expeditiously resolve issues, iron out bottlenecks and make decision-making transparent. The Directorate General of Hydrocarbons (DGH), which had been at the centre of controversies, is looking to start with a clean slate by supporting exploration and production (E&P) activities of oil and gas to cut down import dependence. Dharmendra Pradhan, Union Petroleum Minister

The IAS officer, who took over as the head of DGH last month, in his first message on the regulator’s website said accelerated indigenous exploration efforts are required to meet Prime Minister Narendra Modi’s target of reducing import dependence by 10 per cent to 67 per cent by 2022. According to Chakraborty, DGH’s contribution in creating a progressive and conducive atmosphere for the E&P sector would be “to adopt the role of an enabler, facilitator and ensure a level-playing field”. Reaching out to E&P companies and service providers for “all-out positive support”, he invited stakeholders to provide suggestions and ideas on upcoming projects. “At the same time, I urge my able DGH team to further expand their horizon and deliver to newer expectations to the best of their capacities,” he said.

Offshore World | 47 | April-May 2016

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PROJECT UPDATE

Media Barter with gulfoilandgas.com

Projects Database Petrochemical Plants and ReďŹ neries

Major Projects in the Middle East, Africa and Caspian Sea

Project

Country

Value ($)

Status

Middle East Bahrain Deep Gas Exploration Project

Bahrain

Bahrain Field Development Project

Bahrain

Atrush Block Development

Iraq

Execution 1,500,000,000

Execution Execution

Badra Contract Area Halfaya Contract Area Development Zubair Oil Field Development

Iraq Iraq Iraq

3,520,000,000

Execution Execution Execution

Gathering Center 32

Kuwait

1,000,000,000

Bidding

Jurassic Non Associated Gas Production Programme

Kuwait

4,000,000,000

Bidding

Offshore Block 50

Oman

Execution

Oman Block 8

Oman

Execution

Ras Markaz Oil Storage Terminal

Oman

500,000,000

Bidding

AI-Shaheen Offshore Field Development

Qatar

6,000,000,000

Execution

Barzan Gas Development Project

Qatar

10,000,000,000

Execution

Bul Hanine Field Expansion

Qatar

11,000,000,000

Execution

AI-Khafji Offshore Field Development

Saudi Arabia

1,200,000,000

Execution

Khurais Expansion Project

Saudi Arabia

3,000,000,000

Execution

Shaybah Oil Field Development

Saudi Arabia

1,500,000,000

Execution

Wasit Gas Development Program

Saudi Arabia

6,400,000,000

Bidding

ADMA-OPCO Nasr Field Development

UAE

2,000,000,000

Execution

Gulf Petrochem- Fujairah Oil Storage Terminal

UAE

100,000,000

Execution

Sahil, Qusahwira & Mender Fields

UAE

1,000,000,000

Bidding

Sharjah Western Offshore Concession

UAE

135,000,000

Execution

Africa

Country

Value ($)

Status

Angola - Block 20

Angola

Execution

Angola- Block 21

Angola

Execution

Abu Madi West License - Nooros Prospect

Egypt

Execution

www.oswindia.com

Offshore World | 48 | April-May 2016

PROJECT UPDATE North West Gemsa Concession

Egypt

Execution

Zohr Gas Field

Egypt

Block 11 - Hilala Field

Ethiopia

Execution

Expanded Shallow Water Tano (ESWT) Block

Ghana

Execution

Alba Field

Guinea

Block Cl-103

Ivory Coast

16,000,000,000

850,000,000

Execution

Execution Execution

Block L16 Blocks L27 & L28 LB-6 and LB-7 Blocks Block C-10 Blocks C8, C12, and C13 Circle Oil - Sebou Block Tendrara Lakbir Licence R3/R4 PSC Area OML 113- Aje Field OML 120- Oyo Field

Kenya Kenya Liberia Mauritania Mauritania Morocco Morocco Niger Nigeria Nigeria

Caspian Region

Country

Value ($)

Status

Azeri-Chirag-Gunashli (ACG) Project

Azerbaijan

20,000,000,000

Execution

Bahar Field Development

Azerbaijan

1,000,000,000

Execution

Shah Deniz Offshore Gas & Condensate Field

Azerbaijan

Shah Deniz Stage 2 Development

Azerbaijan

28,000,000,000

Execution

Farzad-B (Forouz B) Offshore Gas Field - Farsi Block

Iran

5,000,000,000

Execution

Kish Gas Field Development

Iran

12,000,000,000

Execution

Mansourabad (Mansoor Abad) Oilfield

Iran

Execution

Sardare Jungal Gas Field

Iran

Execution

South Pars Phase 19

Iran

Execution

South Pars Phases 20 & 21

Iran

6,000,000,000

Execution

BNG Contract Area

Kazakhstan

100,000,000

Execution

Chinarevskoye Oil & Gas Condensate Field

Kazakhstan

2,110,000,000

Execution

Karachaganak Oil & Gas Field

Kazakhstan

15,000,000,000

Execution

Kashagan Oilfield

Kazakhstan

136,000,000,000

Execution

Rostoshinskoye Subsoil Area

Kazakhstan

Tengiz Field

Kazakhstan

Lebedinskiy Oil & Gas Condensate Block

Russia

Messoyakha Oil and Gas Fields Development

Russia

Nagumanovskoye Oil, Gas and Condensate Field Development

Russia

Study

Novoportovskoe Oil & Gas-Condensate Field

Russia

Execution

Vladimir Filanovsky Field

Russia

Yuzhno-Yamskoy License Area

Russia

www.oswindia.com

Offshore World | 50 | April-May 2016

Execution

Execution 23,000,000,000

Execution Execution

18,000,000,000

3,500,000,000

Execution

Execution Study

PRODUCTS

INDUSTRIAL GEAR UNITS NORD Drivesystems added a new size with 190 kNm output torque. The Series now comprises 9 sizes and covers torques from 25 to 250 kNm. The addition of the new size 14 units allows for configurations tailored even more precisely to individual applications. Featuring a single-piece UNICASE housing as is standard for all NORD gear units, they achieve a longer bearing life than gear casings from jointed parts and ensure efficient power transmission and high tolerance for load peaks and jolts. They can be assembled as two or three-stage helical inline or helical bevel gearboxes with nominal transmission ratios from 7.1:1 to 400:1, or even up to 30,000:1 with an auxiliary primary stage. The input and output direction can be freely selected. NORD industrial gear units can be mounted on any of the six sides. The manufacturer configures industrial geared motors for a diverse range of uses from steel works to process plants. Application-specific features and options include reinforced bearings and shafts, extra-large bearing distance, extended output shafts, and Drywell designs with an additional oil drip disc and a leakage oil display or oil sensor. Disc and drum brakes, dual-gear setups, auxiliary motors, IEC motor adapters, turbo couplings, axial fans, motor swing bases, torque limiting backstops, and cooling and heating systems are available as well. For details contact: NORD Drivesystems Pvt Ltd 282/2, 283/2, Village: Mann, Tal: Mulshi, Adj Hinjewadi MIDC II Pune, Maharashtra 411 057 E-mail: jyoti.mishra@nord.com

NORD Drivesystems offers drives with advanced condition monitoring capabilities that support predictive maintenance. NORD employs frequency inverters with an integrated PLC to monitor the complete drive system, evaluate sensor data, and assess the system state by means of intelligent algorithms. An industrial gear unit demonstrates the condition monitoring approach based on sensors and dedicated evaluation technology. Vibration and oil sensors provide crucial live data about the wear and tear. Vibration analysis then enables conclusions about the state of the bearings as well as the gearing, and oil analysis can help determine when the lubricant needs changing. For details contact: NORD Drivesystems Pvt Ltd 282/2, 283/2, Village: Mann Tal: Mulshi, Adj Hinjewadi MIDC II Pune, Maharashtra 411 057 E-mail: jyoti.mishra@nord.com

ONLINE CALCULATION AND CONFIGURATION

MULTI-GAS MONITORS Industrial Scientific offers the Ventis Pro Series multi-gas monitors. The Ventis Pro Series is backed by the industries only guaranteed for life warranty and offers a wide range of sensor options to detect up to five gases. The Ventis Pro4 is compatible with four of the following sensors: LEL/CH4, O2, CO, CO/H2 Low, H2S, SO2, NO2 or HCN making it ideal for industries such as fire service, steel and construction. The Ventis Pro5 detects up to five gases including any covered by the Pro4 in addition to NH3, CO2/ hydrocarbon IR, CO2/CH4 IR and CO/H2S. Industries such as oil and gas, petrochemical, power generation, metal and coal mining, gas utilities and refrigeration, which typically need a larger five-gas instrument, can easily transition to the smaller, lighter Ventis Pro5. Both the Ventis Pro4 and Pro5 are equipped with a variety of new safety features that raise the bar on worker safety. iAssign Technology tracks users and sites in real-time using Near Field Communication (NFC) to help safety managers identify and address jobsite gas hazards and improve asset management. A dedicated panic button and man-down alarm help to alert nearby workers when someone is in distress or has lost consciousness, Acknowledgeable gas alerts let users know when they are in the presence of gas below the low alarm level enabling them to take safety precautions while continuing to work,Alarm action messages provide written instructions during low and high alarm events, helping workers to react appropriately. For details contact: Industrial Scientific Corpn 1 Life Way, Pittsburgh, PA 15205-7500, U.S.A. Tel: (412) 788-4353, (412) 788-4353, Fax: (412) 788-8353 E-mail: ekeblusek@indsci.com

CONDITION MONITORING & PREDICTIVE MAINTENANCE

This innovative idea by Quintex GmbH is already established using an easyto-use overpressure system. Fabrication and assembly is now simplified by the ‘release’ operation by a gas detector. No sophisticated technology is required using the Quintex program, allowing the parameters to be quickly set which then automatically ‘select’ the required enclosure type and size calculating the price instantly for the created system using standard ‘off-the-shelf ’ components. Using calculation programme “Calculation for pressurised enclosures” one can configure a system suitable for operation in an Atex Zone 1 or 2, gas or dust environment certified area by calculation. Often you may find yourself in a situation where you are required to supply a minimum quantity of assembled units and it is not cost-effective or viable to obtain the necessary Atex approval from a certified body. Quintex have already paved the way with their SPZ Series standard sized enclosures (specific for connections under low pressure) to allow all customers to carry out their own installations and assemblies using an approved over-pressure system that is already approved and certified for use without any necessary flushing phase or pre-set requisites. The online configurator is there to assist you with the design and valuation. It is easy and simple to use by entering only 4 key factors. These self-explanatory input fields are entered in a normal manner and by the simple click of a button are then interpreted and calculated with the result appearing in a new programme window. For details contact: Quintex GmbH i_Park Tauberfranken 13, Lauda-Königshofen Baden-Württemberg 97922, Germany Tel: +49 (9343) 6130-118, Fax: +49 (9343) 6130-105 E-mail: anja.budow@quintex.inf

Offshore World | 51 | April-May 2016

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PRODUCTS MODERN APPROACH TO PHYSICAL MODELLING & SIMULATION MapleSim offers a modern approach to physical modelling and simulation, dramatically reducing model development and analysis time while producing fast, high-fidelity simulations. The latest release provides a variety of new features that streamline the user experience, expand modelling scope, and strengthen connectivity with other tools. Additions include interface changes to improve workflow, new and expanded component libraries, and extensions to toolchain connectivity. MapleSim 2016 provides numerous enhancements to provide a smooth, more streamlined user experience. These improvements include task panels that appear automatically as needed and then disappear again to maximize model workspace, redesigned layout that ensures tools are readily available at the moment they are needed, and a new search bar that provides a single point of access for searching help pages, component libraries, examples, attachments, templates, and models from the MapleSim Model Gallery. MapleSim 2016 also includes an expanded multibody component library to support contact modelling, which covers a variety of surface shapes and enables engineers to quickly model contact between different objects in their model. In addition, it comes with a collection of built-in apps that provide point-and-click access to powerful Maple-based analysis and utility tools from within the MapleSim environment. Using these apps, engineers can perform parameter sweeps, Monte Carlo simulations, code generation, and more without any knowledge of Maple. For details contact: MapleSoft 615 Kumpf Drive, Waterloo, ON N2V 1K8, Canada Tel: +1 519 747 2373 ext 352 E-mail: tgeorge@maplesoft.com

IRM Systems (IRMS) offers the Valve Integrity Management Solution (VIMS), an innovative method of maintaining critical pipeline valves to the highest performance standards and criteria that can save up to 70% in lost production, excluding the substantial cost of associated labour, equipment and specialists. VIMS was developed in direct response to the distinct lack of analysed data associated with valve integrity and maintenance in the industry. Following a comprehensive audit of the number - and condition - of all valves on a designated pipeline, IRMS logs and analyses the data, integrating it via the VIMS into the operator’s existing systems and processes. Data on individual valves and assets can then be immediately accessed, in order to review a full range of benchmarked factors in, for example, design, construction, maintenance and reliability. By using this standardised approach to valve integrity maintenance - which relies upon solid risk and reliability engineering – operators can make informed decisions about inspection plans and repairs, saving time and money. For details contact: IRMS UKWA Aberdeen, Scotland, U.K. Tel: +44 1224 224 416 E-mail: d.obatolu@irm-sys.com

SHAFT COUPLINGS

MULTI-PARAMETER WATERPROOF METER Hanna Instruments offers HI98194 multi-parameter, waterproof and carriageable meter that monitors most important water quality parameters like pH, mV, ORP, EC, TDS, resistivity, salinity, seawater σ, DO, atmospheric pressure and temperature. This meter has digital probe which directly measure pH, EC, TDS and then meter calculate other parameters. The probe transmits readings digitally to the meter, where data points can be displayed and logged. The complete system is simple to setup and easy to use. Feature backlit graphic LCD display up to 12 parameters simultaneously. It is waterproof protected. The HI7698194 probe features a quick connect DIN connector that makes a waterproof connection with the meter. The probe and meter automatically recognize the sensors that are connected. Integrated temp sensor allows for automatic temp compensation of pH, conductivity and dissolved oxygen measurements. The meter features a built-in barometer with userselectable units for dissolved oxygen pressure compensation. Quick calibration provides a speedy, single point calibration for pH, conductivity and dissolved oxygen. For details contact: Hanna Equipments (India) Pvt Ltd 3/4/5/6 Aum Sai Bldg, Plot 23 C, Sector 7 , Kharghar, Navi Mumbai 410 210 Tel: 022-27746554, 27746555, 27746556, Fax: 91-022-27746557 E-mail: sales@hanna-india.com www.oswindia.com

VALVE INTEGRITY MANAGEMENT SOLUTION

Essential components for torque measuring flanges in test benches are shaft couplings, which reliably compensate for any shaft misalignments. Based on the tried and tested, backlash-free and torsionally rigid ROBA-DS construction series, mayr power transmission offers compensating couplings which are specially tailored to the high requirements placed on them in measuring flanges. The misalignments cannot be completely eliminated due to the existing tolerances in the measurements of the components used and the external influences. Therefore torsionally rigid shaft misalignment compensation couplings are used together with the measuring flange. mayr power transmission offers ROBA-DS compensating couplings, which are especially tailored to the requirements placed upon them by modern measuring flanges. The ROBA-DS disk pack couplings compensate for radial, axial and angular shaft misalignments. They thus not only ensure precise measurement results, but also protect the bearings installed in the shaft train against unnecessary loads and therefore against unnecessary downtimes and costs. On the ROBA-DS couplings, the nominal torques stated in the catalogue can be used without any restrictions. The couplings are compact, and simultaneously unite high performance density with completely backlash-free function. They transfer torques up to the nominal torque completely backlash-free and with a consistently high torsional rigidity. For details contact: National Engg Co (NENCO) J-225 MIDC Bhosari, Pune, Maharashtra 411 026 Tel: 020-27474529, Fax: 91-020-27470229 E-mail: nenco@nenco.org

Offshore World | 52 | April-May 2016

PRODUCTS INSTRUMENT FOR VAPOUR PRESSURE LPG/NATURAL GAS 2ND STAGE TESTING REGULATORS AMETEK Grabner Instruments offers a versatile and portable vapour pressure tester - the MINIVAP VP Vision. The analyzer features significant improvements in terms of measurement range that allows one instrument to measure gasoline, jet fuel, crude oil, LPG and solvents (without needing to attach a pressure regulator). The analyzer is certified to work in cold, hot and damp climates and has ability to withstand vibrations and heavy shocks coming from any direction. It is the ideal tester for mobile laboratories, military applications and harsh, demanding environments. The MINIVAP VP Vision is the first vapour pressure tester to demonstrate excellence in engineering and quality. It offers an extended pressure range of 0 to 2,000 kPa. Long-term testing has demonstrated an unmatched repeatability of less than 0.2 kPa. Grabner’s 2D-Correction (273 points) and exact piston positioning guarantee that accurate and precise results are received over the full measuring range. In addition, the MINIVAP VP Vision features Grabner´s Sampling Pro valve the best-in-class, pistonbased design for minimizing cross-contamination between various sample types. The MINIVAP VP Vision uniquely combines ease of use with flexibility. A modern, applike user interface makes it easy to select, start and follow measurements directly on an industry-proven 10” touch screen. Grabner’s Cockpit PC software allows users to consolidate measurement results and statistics from multiple locations at one central lab and to store measurement data at any chosen location via direct Ethernet and LIMS-connection. The software can be accessed through a secure VPN tunnel, allowing true mobile access to instruments from any place at any time.

Mesura of France, a leading manufacturer of gas regulators, systems and services for regulating and measuring of natural gas, and Nirmal Industrial Controls Pvt Ltd, India’s leader in the field of high pressure regulators, slam shut valves and gas conditioning, pressure regulating and metering stations set up a JV, Mesura Nirmal Gas Controls Pvt Ltd, offers highly accurate, ruggedly constructed, attractively priced and ex-stock delivery of LPG and natural gas regulators. Safety shutoff devices can be supplied in a gas train. Regulators are well-protected against corrosion with consistent powder coating. It has extreme temperature-resistant diaphragms, SS screws and bolts, and ¼” connections for inlet pressure gauge of 1 to 17 Bar/outlet pressure gauge of 30 to 300 mBar, 30 Nm3/hr of LPG flow, and 1/2” x 1” NPTF endconnection. Flows tested in accordance with UL144. The Cavagna Group’s top-line of LPG regulators for residential, commercial and industrial use is also offered by the JV. It is the 2nd stage regulator for residential gas banks. Suitable for commercial use in hotels, malls, hospitals, IT parks, educational institutes and ideal for use after 1st stage directly to the inlet of user appliance or in installations with Pressure Governors. It finds application in hot air generators, furnaces, gas engines, burners and boilers, painting, powder coating, glass and ceramic, food, agriculture, automobile and foundry industry. For details contact: Nirmal Industrial Controls Pvt Ltd Samriddhi Bldg, 1st Floor, LBS Marg Mulund (W), Mumbai 400 080 Tel: 022-67746282, 67746200 E-mail: tawde@nirmalindustries.com / vrushank.shukla@mesuranirmal.com

SOLUTIONS FOR DECK MACHINERY

For details contact: Grabner Instruments Messtechnik GmbH Dr Otto Neurathgasse 1, A-1220 Vienna, Austria Tel: +43 1 282 16 27-110, Fax: +43 1 280 73 34 E-mail: sales.grabner-instruments@ametek.at

Several applications like mooring and tugger winches, anchor handling systems, traction and storage winches, capstans and windlasses offer a bench test for the 700C Series in mediumlight power cases, and HDP/HDO Series in medium-high power cases. The 300 Series and 700T Series are used for pinion ring transmission systems. The winch drum is generally supported on the opposite side of the gearbox, but strong bearings in the 700C Series enables it to have a console set-up as well.

GAS ANALYSERS The Forbes Marshall CODEL Model GCEM4000 can be used as a single gas or multi-gas monitoring station capable of measuring up to 7 gases in a single instrument. These in-situ probe type gas analysers are easy to install and ensure drift-free calibration, eliminating expensive calibration and test gases. For details contact: Forbes Marshall Mumbai-Pune Road, Kasarwadi, Pune, Maharashtra 411 034 Tel: 020-27145595, Fax: 91-020-27147413 E-mail: corpcomm@forbesmarshall.com

Hydraulic and electric driven variations, as well as in-line or right angled configurations, are available throughout the Bonfiglioli range. For details contact: Bonfiglioli Riduttori Spa Via Giovanni XXIII 7/a 40012 Lippo di Calderara di Reno, Bologna, Italy Tel: +39 051 647 3932 E-mail: MariaCristina.Venturoli@bonfiglioli.com / ameet.rele@bonfiglioli.com

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EVENTS DIARY

OSEA2016

EGYPS 2017 Date: 14 - 16 February 2017 Venue: CICEC, Cairo, Egypt Event: EGYPS 2017 brings together Egyptian and North African government representatives, key project owners, NOCs and IOCs, international service providers, EPC contractors, consultants and financiers to address the evolving opportunities in the Egyptian and North African energy arena. The event, held under the high patronage of His Excellency Abdel Fatah El Sisi, President of The Arab Republic of Egypt, will help you identify Egypt’s future project requirements, the country’s short and long term plans, strategic priorities and masterplans and gain insights into the wider North African oil and gas sector.

Date: 29 November - 2 December 2016 Venue: Marina Bay Sands, Singapore Event: Taking place every second year, OSEA is Asia’s best known Oil & Gas event. The 21st edition is from 29 November – 2 December 2016 in Marina Bay Sands, Singapore. With a comprehensive showcase of oil & gas exploration and production innovations, OSEA continuously attracts international participation, further enhancing its reputation as THE ideal platform to meet new buyers and partners.

EGYPS 2017 technical conference sessions and panel discussions will include critical insights into Egypt and North Africa’s fast evolving hydrocarbon business.

In line with the industry trends and the extensive feedback from the recently concluded OSEA2014 International Conference, the upcoming Conference in 2016 will highlights some of the current trends going on the global hydrocarbon industry viz; Deepwater Exploration & Production; Optimising New and Unconventional Hydrocarbon Assets; Commercial Opportunities in Shale Gas, FPSO and FLNG; Process Safety and HSE; Asset Integrity Maintenance and New Techniques; Terminal, Bunkering, Tank Farms and other Downstream Opportunities; Digital Oil Fields, Communication, Cyber Security and Disaster Management, etc

For details contact: Kathleen Rebello, Marketing Executive dmg events, Middle East 5th Floor, The Palladium, Cluster C, Jumeirah Lakes Towers T: +971 (0)4 445 3738 M:+971(0)55 505 4707 W: www.dmgeventsme.com

For details contact: Singapore Exhibition Services Amy Tan Assistant Manager, Marketing Services DID: +65 6233 6619 Fax: +65 6233 6633 Email: amy@sesallworld.com Web: http://osea-asia.com/

5 th East Africa Oil & Gas Expo 2016

Date: June 10-12, 2016 Venue: Nairobi, Kenya Event: The 5 th Oil & Gas Africa will be a hub for key players in the oil and gas community, attracting leading oil, gas and petroleum companies from around the world. This regional trade event serves the resource-rich east African region and city of Nairobi; Kenya’s major centre of oil and gas activity for many of the leading operators in the country. Kenya has attracted oil & gas companies not only because of its ports and strategic location but also because the government is keen not to be left out of the exploration. Oil discoveries in Uganda and Kenya and gas deposits found off Tanzania and Mozambique have turned east Africa into a hot spot for hydrocarbon exploration. Trade visitors from all over East & Central African countries are being invited directly and in collaboration with several regional trade bodies in Kenya, Tanzania, Ethiopia, Uganda, Somalia, Mozambique & Congo. Though Kenya by itself is one of the biggest markets in Africa, major emphasis is being laid upon attracting traders and importers from neighbouring countries. Oil & Gas Africa will offer participants the opportunity to showcase the industry’s latest achievements and technologies while networking with key figures from the region’s oil and gas sector. The exhibition brings the industry together in a forum that is conducive to business. For details contact: Expogroup Estate NH-17, Porvorim, Bardez, Goa, India Tel: + 91-832-6451777/666/555 | Fax: + 91-832-2410771 Email: ind@expogroup.net www.oswindia.com

Refining & Petrochemicals World Expo 2017 Date: February 14 -17, 2017 Venue: BCEC, Goregaon (East), Mumbai, India Event: CHEMTECH will organise Refining & Petrochemicals World Expo 2017 and technical conference during CHEMTECH World Expo 2017 scheduled from February 14-17, 2017 in Bombay Exhibition Grounds, Goregaon (East), Mumbai and will once again create a platform for the professionals from India and overseas to witness the latest trends in technologies during the exhibition and provide opportunity to interact during the concurrent conference. The high-level technical conference in which key players in the global refinery and petrochemical sector will meet to share knowledge and learn about best practices and the latest advancements in this developing sector of the oil and gas downstream industry. For details contact: Jasubhai Media Pvt Ltd 3rd Floor, Taj Building, 210 D N Road, Fort Mumbai - 400001, Maharashtra, India Tel : 022-40373636 Fax : 022-40373535 Email: conferences@jasubhai.com Web: http://www.chemtech-online.com/

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RNI No. MAHENG/2003/13269. Date of Publication: 1st of every alternate month.

Engineering & Technology Exposition for Oil & Gas, Power and Shipping Industries

February 2018 Venue: Bombay Convention & Exhibition Centre, Goregaon (East), Mumbai, India Supported By Organised By

Registered Office: Taj Building, 3rd Floor, 210, Dr. D N Road, Fort Mumbai – 400 001, INDIA. Tel: +91-22-4037 3636, Fax: +91-22-4037 3635 Email: sales@jasubhai.com.

• Ahmedabad - 09712148258 • Vadodara - 09712148258 • Bangalore/Hyderabad - 09444728035 • Chennai - 09176963737 • Delhi - 09818148551 • Pune - 09822209183