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CONTENTS

INTERVIEW Unconventional Today…Conventional Tomorrow 16

VOL. 12 | NO. 5 | AUGUST - SEPTEMBER 2015 | 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 Prasenjit Bhowmick, Arun Parab Dilip Parab V Raj Misquitta (Head), Arun Madye

– Dr Aninda Mazumdar, Associate Professor ACSIR, Gas Hydrate Research Group, CSIR-National Institute of Oceanography (NIO)

GUEST COLUMN Coming in from the Cold? Iran’s Energy Sector Gears up for Post-sanctions Era – Thangapandian Srinivasalu, Executive Director, GP Group

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NEWS FEATURES

PLACE OF PUBLICATION: Jasubhai Media Private Limited

210, Taj Building, 3rd Floor, Dr. D. N. Road, Fort, Mumbai 400 001.

Tel: + 91 -22-4037 3636, Fax: +91-22-4037 3635

SALES

General Manager, Sales

India Oilfield Services Market to Reach USD 7.8 Billion by 2020 6 – Vipul Tiwari New Study Highlights Focus Areas for Offshore Operators’ Improvement Efforts 12 – Paul Ziff

Amit Bhalerao (amit_bhalerao@jasubhai.com) Prashant Koshti (prashant_koshti@jasubhai.com)

MARKETING TEAM & OFFICES

Mumbai

Godfrey Lobo / V Ramdas Taj Building, 3rd Floor, 210 D N Road, Fort, Mumbai 400 001 Tel: 91-022-40373636, Fax: 91-022-40373635 E-mail: godfrey_lobo@jasubhai.com, v_ramdas@jasubhai.com Ahmedabad Vikas Kumar 64/A, Phase-1, GIDC Industrial Estate Vatva, Ahmedabad 382 445 Tel.: 91-079-49003636/627, Fax: 91-079-25831825 Mobile: 09712148258 E-mail: vikas_kumar@jasubhai.com Vadodara Vikas Kumar 202 Concorde Bldg, Above Times of India Office R C Dutt Road, Alkapuri, Baroda 390 007 Telefax: 91-0265-2337189, Mobile: 09712148258 E-mail: vikas_kumar@jasubhai.com Bengaluru Princebel M Mobile: 09444728035 E-mail: princebel_m@jasubhai.com Chennai / Coimbatore Princebel M / Yonack Pradeep 1-A, Jhaver Plaza, 1st floor, Nungambakkam high Road, Chennai 600 034 Tel: 044-43123936, Mobile: 09444728035, 09176963737 E-mail: princebel_m@jasubhai.com, yonack_pradeep@jasubhai.com Delhi Priyaranjan Singh / Suman Kumar 803 Chiranjeev Tower, Nehru Place, New Delhi 110 019 Tel: 011 2623 5332, Fax: 011 2642 7404 E-mail: pr_singh@jasubhai.com, suman_kumar@jasubhai.com Hyderabad Princebel M / Sunil Kulkarni Mobile: 09444728035, 09823410712 E-mail: princebel_m@jasubhai.com, sunil_kulkarni@jasubhai.com Kolkata E-mail: industrialmags@jasubhai.com Pune Sunil Kulkarni Suite 201, White House, 1482 Sadashiv Peth, Tilak Road, Pune 411 030 Tel: 91-020-24494572, Telefax: 91-020-24482059 Mobile: 09823410712 E-mail: sunil_kulkarni@jasubhai.com Subscription Rate (per year): Indian - ` 810/-; Foreign - US$ 120 Price of this copy: ` 150/The Publishers and the Editors do not necessarily individually or col­lectively identify themselves with all the views expressed in this journal. All rights reserved. Reproduction in whole or in part is strictly prohibited without written permission from the Publishers.

Jasubhai Media Private Limited

FEATURES Development of Sour Gas Treatment in Indian Offshore Field – Mehtab Shaikh, V K Gajinkar, Amjad Khan and Melwin Raj Early Production Prediction for Unconventional Wells – Sudhendu Kashikar, Hasan Shojaei and Casey Lipp Seismic Induced Monitoring in Oil and Gas Production: What is Really Required?

– Dr Steven Taylor Indigenous Technology for TATB: A Thermally Stable, Insensitive High Explosive having Versatile Applications – Amiya Kumar Nandi and Dr Raj Kishore Pandey Temperature Measurement in the Modified Claus Sulfur Reactor – David Ducharme Oil and Gas Fields Get Smart – Dr Peter Martin

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34 36 38

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TRENDS Products

Printed and published by Mr Maulik Jasubhai Shah on behalf of Jasubhai Media Pvt. Ltd., 26, Maker Chamber VI, Nariman Point, Mumbai 400 021 and printed at Varma Print, Pragati Industrial Estate, N M Joshi Marg, Lower Parel, Mumbai 400 011 and published from 3rd Floor, Taj Building, 210, Dr. D N Road, Fort, Mumbai 400 001.

Editor: Ms. Mittravinda Ranjan, 26, Maker Chamber VI, Nariman Point, Mumbai 400 021.

www.oswindia.com

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Identifying Technologies to Reduce Drilling Budgets in the Low Oil Price Environment 40 – Colleen Kennedy Virtualisation – Software Defines Revolution for Plants 42 – Sanjay Sharma Smart Refinery: Enhance the Productivity of Plant in Manifold 46 – Tim Olsen Most Energy Commodities Continue to Drag Down 48 – Niteen M Jain & Nazir Ahmed Moulvi

PROJECT UPDATE Registered Office: 26, Maker Chambers VI, 2nd Floor, Nariman Point, Mumbai 400 021, INDIA Tel.: 022-40373737, Fax: 022-2287 0502 E-mail: sales@jasubhai.com

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Events Diary 58

Offshore World | 4 | October - November 2015

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NEWS FEATURES

INDIA OILFIELD SERVICES MARKET TO REACH USD 7.8 BILLION BY 2020 In the backdrop of falling crude price, global oilfield services market is anticipated to decline in the future. Simultaneously, decline in number of wells drilled during 2014-15 is expected to lead to a decline in E&P activities in India, which will eventually lead to decline oilfield services market in the country. The article highlights the current and future prospect of Indian Oil Field Services market in detail.

T

he market for oilfield services in India has a great potential for the future with improving demand from oil and gas sector, strong expansion of industrial, infrastructure and service sectors, and anticipated stabilisation of crude oil prices by 2017. Based on service type, oilfield services market in India is segmented into drilling and completion fluid services, coiled tubing services, pressure pumping services, wireline services, Oil Country Tubular Goods (OCTG), well intervention services, completion equipment & services and drilling waste management services. Oilfield services depend on a number of factors such as operating oil and gas wells, deviation in global crude oil prices, political volatility and regulatory framework of the country, etc.

Global oilfield services market is anticipated to decline in the future, due to reduction in drilling activities and decreasing crude oil prices. The world rig count declined by 1,526 from 3,658 in December 2010 to 2,132 in April 30, 2015. This dramatic fall in world rig count led to the decline in global oilfield services market.

Since 2012, the oil and gas sector in India witnessed a decline in demand, despite higher production of crude oil. This has ultimately reduced crude oil prices in India and further, negatively impacted growth in E&P activities. Moreover, decline in number of development wells drilled during 2014-15 is expected to lead to a decline in E&P activities in the country. This decline in E&P activities impacted oilfield services market to a great extent.

With the implementation of New Exploration Licensing Policy (NELP), number of blocks being allocated under different bidding rounds of NELP has increased and ensured a healthy competition between private and national oil companies such as Oil and Natural Gas Corporation (ONGC) and Oil India Limited (OIL), which accounted for a lion’s share in the oil and gas exploration and production market. These NELPs help companies attract private and foreign investments, which contributed to growth of exploration and production market in India. Also, 100 per cent FDI has been allowed in oil & gas exploration activities in India, thereby encouraging private sector participation and investments in the sector.

A total of 360 blocks have been offered under the 9 NELP rounds. Out of these 360 blocks, 282 blocks have been bid for, of which 261 blocks have been awarded, which include Production Sharing Contract (PSC) signing for 254 blocks. PSC signing for over 250 blocks is expected to boost E&P activities, and hence, oilfield services market in India during 2015-2020. As on 2014, 148 blocks were operational and remaining 106 blocks have been relinquished. Under NELP-X (which is to be held in March 2016), a total of 46 blocks are expected to be offered in 13 basins for exploration of oil and gas. These blocks would be based in basin of Gujarat-Kutch, Gujarat-Saurashtra, Mumbai, Kerala-Konkan, Cauvery, Krishna Godavari, Mahanadi-NEC, Andaman, Bengal, Punjab plain, Rajasthan, Cambay & Deccan Syneclise. Out of these 46 blocks, 17 blocks would be offered to onshore areas, 15 blocks to shallow water and the remaining 14 blocks to deep water areas. Allocation of blocks under NELPs is expected to boost exploration and production activities and drive growth in oilfield services market in India during 2015-2020.

India’s oil and gas exploration and production activities are forecast to grow at a CAGR of 2.37 per cent during 2015-2020 and investments in the exploration and production division is projected to reach USD 27.25 billion by 2020. Oil and gas exploration sector witnessed significant growth over the past few years due to the implementation of NELP. Consequently, exploratory activities in several deep water and shallow areas, which were either unexplored or poorly explored, have been appraised through surveys and exploratory drilling.

Onshore oilfield services market in India accounted for a revenue share of more than 70 per cent in

www.oswindia.com

Offshore World | 6 | October - November 2015

NEWS FEATURES

India oilfield services market during 2010-2014. Onshore oilfield services market in India was valued at USD 5.40 billion in 2014 and is projected to reach USD 5.71 billion by 2020, growing at a CAGR of 2.26 per cent during 2015-2020.

Growth in the onshore oilfield services market can be attributed to the increase in number of onshore rigs from 88 in 2008 to 122 in 2014. Allocation of more onshore blocks under various NELP bidding rounds during the coming years is expected to propel growth in onshore exploration activity and drive India onshore oilfield services market.

Rising investments from ONGC and increasing rig count is projected to propel growth in India offshore oilfield services market at a faster rate of 10.82 per cent during 2015-2020, compared to onshore oilfield services market in India.

India offshore oilfield services market is projected to reach USD 2.16 billion by 2020 from USD 1.29 billion in 2014. ONGC accounted for the highest share in operating offshore rigs in India with 39 rigs as of 2014. The total offshore rig count in India as of 2014 was 59 rigs compared to 50 rigs in 2013, registering a Y-o-Y growth of 18 per cent. Increase in number of oil discoveries in southern region of India and rise in number of offshore exploration wells being drilled across the region is anticipated to drive India offshore oilfield services market during 2015-2020.

energy demand in the country. All these factors are projected to increase oil and gas production and propel growth in India oilfield services market during the ensuing years.

In 2014, Gujarat, Rajasthan and Assam garnered the highest share in India oilfield services market, as these states have maximum oil and gas exploration and production activity in the country. Western region dominates India oilfield services market due to huge investments from major E&P companies and rise in drilling activities in the region. Around 7,032 and 362 wells are proposed to be drilled in Gujarat and Rajasthan, respectively by 2020.

ONGC and OIL, the two national oil companies along with 30 private and joint venture companies are engaged in oil and gas exploration and production (E&P) activities in India. Some of the major private oil and gas companies operating in India include Essar Oil Ltd, Reliance Industries Ltd (RIL), Adani Welspun

India oilfield services market is being driven by high per capita energy consumption, fluctuations in crude oil prices, increase in GDP, and growth in the number of blocks coming under operational phase. Increase in per capita energy consumption implies to rising demand for oil and gas, which is anticipated to be addressed by increase in number of E&P activities, thereby driving growth in India oilfield services market. Developments in industrial, infrastructure and service sectors is anticipated to drive GDP growth in India and thereby boost www.oswindia.com

Offshore World | 8 | October - November 2015

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NEWS FEATURES “Oilfield Services market in India is projected to grow due to increase in number of blocks being awarded under different NELP rounds and subsequent investments made by IOC’s and other private players. Drilling services accounted for a maximum share in revenues due to various critical activities such as directional drilling, hydro fracturing services and cementing, etc.”

- Karan Chechi, Director, TechSci Research Exploration Ltd, Cairn Energy India Pty Ltd, BHP Billiton Pty Ltd, and British Gas Exploration and Production (India) Ltd. ONGC is the largest oil and gas exploration and production company in India, followed by Oil India Limited (OIL). In 2014, ONGC accounted for a total of 112 rigs, which includes both onshore and offshore rigs, whereas OIL had only 15 rigs, including onshore and offshore drilling rigs. ONGC made 14 new oil and gas discoveries in FY14. Oil exploration in India has increased over the years and resulted in an increase in the number of drilling activities. ONGC intensified its exploration activities focusing on long-term growth. During 2010-2014, the rig count in India witnessed rapid growth indicating increase in exploration and production activities to reduce dependence on imports. This increase in the number of drilling activities is anticipated to fuel growth in India oilfield services market over the next five years.

Investment plans of companies such as ONGC, OIL and Hindustan Oil Exploration Company Limited (HOEC) in the public sector, and Reliance India Limited (RIL) and CAIRN India in private sector is expected to push revenue growth in India oilfield field services market during the coming years. Further, Government’s decision of moving from Production Sharing Contract to Revenue Sharing Contract regime is expected to drive growth in India oilfield services market. Auctioning of 69 idle oil and gas fields of state-owned ONGC and Oil India to private companies on new Revenue Sharing Model is forecast to further boost the market for oil and

gas exploration and production in the future. Various PSU companies dealing in oil and gas exploration and production activities in India are planning to invest heavily in E&P activities and this is projected to drive growth in India oilfield services market during the coming years.

As the number of development wells is increasing and is estimated to reach 549 by 2020, more development and drilling activities are scheduled for completion during 2015-2020. Also, investments worth USD 2875.8 million are being made in NELP-IV to NELP-IX, suggesting that exploration activities are forecast to increase. India drilling services market is projected to increase from USD 2.77 billion in 2015 to USD 3.40 billion by 2020.

Due to regulatory delays, companies such as BHP Billiton Ltd and Santos have exited exploration blocks that were awarded to them under NELP rounds. BHP was awarded 10 blocks, of which six blocks were allocated in the seventh round and three blocks in the eighth round of auction under NELP. The company decided to relinquish 9 out of 10 blocks due to its inability to carry out exploration operations in these blocks, delay in defence approval and timely clearances. Santos, Australia’s third-largest oil and gas producer, was awarded two blocks in south-eastern part of Kolkata in the sixth round of NELP. The company plans to exit these two blocks due to their maritime boundary dispute with Bangladesh and defence restrictions. Government is trying to persuade BHP Billiton Ltd. and offering partnership with ONGC. Oil and Natural Gas Corporation has considered the idea of purchasing majority stakes in blocks awarded to BHP Billiton Ltd, and receiving timely approvals. Due to exit of BHP Billiton Ltd and Santos from the oil and gas sector, which was confronted with regulatory and pricing issues and lack of marketing freedom, is forecast to have a negative impact on the sector and thereby affect foreign investments in the sector.

Vipul Tiwari Consultant – Energy & Power TechSci Research Email: vipul.tiwari@techsciresearch.com www.oswindia.com

Offshore World | 10 | October - November 2015

15th Edition

Chemical | Pharma & Biotech | Oil & Gas | Pumps, Valves Pipe & Fittings | Filtration & Separation

Who’s Who is an ‘Exhaustive Listing and Fact Book on Chemical Process Pharma & Biotech, Oil & Gas, Pumps Valves Pipes & Fittings, Filtration & Separation Don’t miss this unbeatable brand building opportunity. Advertise in the biggest & best of the India’s Process Industry & watch your Company grow. We look forward to your participation in our 15th Edition.

We would like you to know that Who’s Who has progressed by leaps & bounds over the last 14 editions. Thank you for your support. We are now in the process of compiling the 15th Edition. Who’s Who is an exhaustive listing & Fact Book on the process engineering companies in the Chemical, Pharma & Biotech, Pumps Valves Pipes & Fittings, Filtration & Separation. It also carries extensive information on the Oil & Gas Industries and Industrial & Process Automation. The database covers more than 10,000 participants at our ChemTECH Events.

Who’s Who is an important part of the literature accessed by Purchase Managers from these industries for their research before procurement. It is also made available to visitors to our stalls at international expositions who evince interest in Indian products. The whole compilation rendered on CD is a big hit with these visitors. The international audience can also access Who’s Who at the libraries of Indian Trade Chambers abroad.

Important Segments 2. Pharma Process Equipment / Packaging 4. Plant & Machinery 5. Pumps, Valves, Pipes & Fittings 6. Filtration & Separation 7. Industrial & Process Automation 8. Water & Waste Management 9. Materials Handling & Logistics 10. Engineering, Procurement & Construction 11. Oil & Gas 1. Pharma & Biotech

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: industrialmags@jasubhai.com

NEWS FEATURES

NEW STUDY HIGHLIGHTS FOCUS AREAS FOR OFFSHORE OPERATORS’ IMPROVEMENT EFFORTS The paper, presented by Solomon Associates, highlights the key areas of operations where best practices has been taken by the industry’s leading producers that lead to excellence performance results in offshore industry. The study is focusing two main families of metrics – operating costs and uptime/production reliability – where best practices can provide operators with clear paths to cost savings and significantly increased productivity on assets.

E

arlier this year, Solomon Associates released a comprehensive benchmarking study for the global offshore industry. The Worldwide Offshore Production Operations Performance Analysis studied operating cost, production efficiency and other technical key performance indicators (KPIs) from 130 floating production facilities and fixed platforms. The new report is the largest study ever done for the worldwide offshore sector, with a total analysed throughput of over 7.6 million barrels per day, involving offshore operations in 20 countries around the world.

By focusing on two main families of metrics – operating costs and uptime/ production reliability – the study revealed key areas of operations where best practices by the industry’s leading producers lead to excellence performance results. The insights gleaned from analysis of the data indicate a number of areas of offshore operations where best practices can provide operators with clear paths to cost savings and significantly increased productivity on assets.

Rigorous Discipline in Boat and Helicopter Runs When you go grocery shopping, odds are you make a list and go at regular intervals. You’ve learned from experience that being strategic in stocking your kitchen saves you money and solidifies a routine. The same principle applies to your offshore material runs. Resupply boats typically carry as much as three or four flatbeds worth of cargo and cost thousands to run. Helicopters which ferry workers back and forth are even more expensive, costing several thousand dollars per hour. With costs that high, operators who use rigorous discipline in their logistics management realise significant savings over their competitors.

Best-in-class operators put strategic thought into exactly what supplies they need to deliver to complete their weekly activities. Spur of the moment runs are

forbidden except in extreme cases. Similarly, they run their helicopter schedules as strictly as a city bus line, eliminating one-off trips for stragglers or special cases. If you miss your ride, you will just have to wait for the next one. Companies that define the purpose of each trip and force people to stick with it have a lower usage rate than companies who lack that discipline.

Proactive Maintenance You wouldn’t wait until your car’s engine died to get the oil changed and the fluids checked because you know the financial risk far outweighs the cost of routine preventive maintenance. The same holds true for offshore operations. In cost challenged times such as we are experiencing now, it’s tempting to defer maintenance activities in order to save money, but that’s a shortsighted approach.

Empirical evidence demonstrates that disciplined preventive maintenance results in lower costs than reactive maintenance programmes.

Scheduled preventive maintenance costs may seem difficult to swallow, especially when you’re not currently experiencing any issues with your equipment. But by being proactive with maintenance, operators can nominally save significant costs in repairs – and that’s not even counting if something catastrophic occurs.

When you add to that the cost of lost production time, the price you pay for skipping routine maintenance skyrockets. Why risk losing millions just to save a few thousand dollars now?

Mutually Beneficial Partnerships Imagine for a moment your physicians changed the way they did business.

Instead of profiting on selling you treatments after you were already sick, they implemented an incentive structure which rewarded them for keeping you well.

They studied your current health and lifestyle, then made recommendations for preventive health measures that were specific to you. The longer you went without getting sick, the higher their incentive. We’d probably have a lot more healthy people walking around, and the physicians office would be a much happier place to visit.

Best-in-class offshore operators apply this philosophy to their chemical management system by forming partnerships with their vendors, which make them mutually invested in the health of the equipment and the facility while maintaining some in-house expertise as well.

Source: Solomon Associates www.oswindia.com

Operators who don’t throw excessive chemicals at operations ‘just in case’ and instead rely on a risk-based inspection process wind up spending much less on Offshore World | 12 | October - November 2015

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Source: Solomon Associates

chemical purchases. Naturally, this isn’t good news for the chemical vendors.

So these operators have changed the business framework to incentivise their providers to keep their operations healthy. Partner vendors using a comprehensive chemical management system leverage scientific leading indicators to identify exactly how much and where a chemical is needed. The vendor is then rewarded on performance and the accuracy of the analysis. They make their profit by keeping you healthy instead of selling you more chemicals than you need.

at the vendor’s shipping yard, ready to ship out to the platform on short notice.

These operators work out strategic contracts with their vendors and service companies to ensure that everything from portable cranes to welding spreads to boats are on call and ready to be put into action quickly.

Proven Technology Sometimes it seems like every time you turn around there’s a lab creating new technology designed to let you push into new frontiers of offshore E&P. It can be incredibly tempting to hop on the latest bandwagon that promises to let you go deeper and withstand higher pressure. Everyone wants to be the first to get to the next big deposit.

But there’s a big risk with being on the ‘bleeding edge’ of production technology.

In many cases, fundamental design flaws only emerge after a new technology is put into practice for a few years. Subsea equipment can cost from hundreds of thousands to millions of dollars per day to operate. If you have to intervene to repair a downhole device or other piece of equipment, you could wind up spending tens of millions of unnecessary dollars.

As engineers, we always want to have the latest and greatest tech to play with. But the business side of offshore exploration has to consider all possible angles, and the data shows that companies that favor effective, proven design philosophies tend to avoid the train wrecks that cost some operators so much money. Integrating expensive equipment into your operations incurs such a high cost that you need it to function effectively for the next couple of decades. If you’re banking your long-term strategy on a new piece of technology that only left the design floor a year ago, you’re taking a big risk with the future of your operations.

The upfront cost of paying to store materials and have workers on call may give some operators pause, but compared to the cost of lost productivity during operational shutdowns, the price is negligible. Being prepared to jump on unplanned opportunities can lower the days of planned downtime, and help mitigate the millions of dollars in revenue you can lose when you aren’t producing.

The tens or even hundreds of thousands of dollars you’ll spend to make sure equipment and labor is available when you need it is clearly justified when it means unexpected downtimes don’t grind operations to a halt. Best-in-class operators have an opportunistic mindset that allows them to be flexible, agile and ready for any eventuality.

Conclusion Many of the best practices outlined here seem like plain, old-fashioned common sense. Our Worldwide Offshore Production Operations Performance Analysis has shown that while these practices are valuable in times of economic strain such as we’re currently experiencing, it’s tempting to let forego proven practices and cut corners or adopt a short-term mentality. By implementing best practices and establishing clear processes designed to turn challenges into opportunities, operators can decrease costs, increase productivity, and join their peers in leading the industry.

Unplanned Downtime Unplanned shutdowns in operations are inevitable and beyond the control of operators. But just because you have to stop operations to conduct emergency maintenance or put a tie-in on the pipeline doesn’t mean productivity has to stop.

The most successful operators plan ahead in order to capitalise on unplanned downtime by performing scheduled maintenance during these windows of opportunity. Crews and equipment are waiting on standby at the shorebase or www.oswindia.com

Offshore World | 14 | October - November 2015

Paul Ziff Executive Vice President Solomon Associates Email: paul.ziff@solomononline.com

INTERVIEW

Unconventional Today…

Conventional Tomorrow

India’s National Gas Hydrate Programme (NGHP) was initiated in 1997 with an intention of developing Gas Hydrate in India, which has significant potential as it represents a large amount of hydrocarbons trapped in the hydrate phase and has an important role to play in highly energy starved country like India.

Dr Aninda Mazumdar, Associate Professor ACSIR, Gas Hydrate Research Group, CSIR-National Institute of Oceanography (NIO) - the government research institution which has been involved geoscientific & seismic data acquisition of gas hydrates reserves in India - discussed the potential, technology and environmental challenges of gas hydrates development in the country with an exclusive interaction with Rakesh Roy.

It is assumed that the potential of gas hydrates worldwide is around 100,000 TCF, which is double the conventional hydrocarbon resources.

www.oswindia.com

Offshore World | 16 | October - November 2015

INTERVIEW Please apprise us the worldwide potential and development of hydrocarbon from gas hydrates.

Methane gas hydrates, the unconventional natural gas source which is mostly found in marine environment, consist of more than 90 per cent of methane (CH 4) and rest water (H 2O). Gas hydrates are stable under specific high pressure - more than 1000 meter of water depth and low temperature - around 5 to 6 degree – condition. In a gas hydrate, the gas molecules are ‘caged’ within a crystal structure composed of water molecules. Normally in a crystal structure gas hydrate, there is one molecule of methane for every six molecules of water.

Per unit volume of gas hydrates contain large amount of gas. For example, if one meter cube of methane hydrate, which is present at the seabed condition at low temperature and high pressure, is brought to the normal room temperature, it will expand and around 164 meter cube of gas and approximately 1 meter cube of pure water will be produced.

So the potential of gas hydrates is huge and the reserve of gas hydrate worldwide is much more than all the fossil fuels like conventional petroleum and natural gas. It is estimated that the worldwide gas hydrates reserve is double the conventional hydrocarbon resources. But there are a lot of problems to monetise the gas hydrates.

The potential of gas hydrates depend on the availability of technology and economic feasibility to extract methane from the hydrate. The nature of the host sediment and the structural/stratigraphic control on hydrate accumulation dictates whether gas can be extracted or not.

Worldwide marine methane hydrates are commonly found in the fractures and fault zone, as disseminated thin layers in clay/silty sediments and as pore filling cement in the sand bodies. Mining of gas hydrates from stratigraphically controlled deposits like sand reservoir is apparently the method owing to high permeability. Mining of fracture controlled hydrate is an engineering and technological challenge.

Various studies have assumed that the total gas hydrates reserves worldwide are extremely large – around 100,000 TCF, but a very small section of such huge reserves is extractable. One of the first pilot scale experiments on exploiting gas hydrates was done in Mallik well in Northern Canada to find out whether the unconventional gas is economical sustainable or not. Subsequently, Japan has carried out pilot scale exploitation of gas hydrates in Nankai Trough for 7 days, but abounded the project due to the technical difficulties. So two things – the sustainability of gas production and the technical feasibility – are the major concerns while exploiting gas hydrates.

Can you please throw some lights on Indian context?

In 2015, under India’s National Gas Hydrate Programme (NGHP-2), geologists discovered thick deposit of sand saturated with gas hydrates around 930 TCF in the Krishna-Godavari (K-G) Basin with the help of Japanese drilling vessel Chikyu. Earlier in 2006, as part NGHP-expedition-1, India discovered significant hydrate reserve in the fractured clay-silt sediments of K-G basin and Mahanadi basins. While the total conventional gas reserves of India is projected around 50-60 TCF, even if 10 per cent of the estimated gas hydrate reserves can be

While the total conventional gas reserves of India is projected around 50-60 TCF, even if 10 per cent of the estimated gas hydrate reserves can be exploited, it can power for the country for a century. exploited, it can power for the country for a century. Andaman and Mahanadi basins also have also great potential for gas hydrate reserves, however more exploratory work has to be carried out for proper assessment.

What are the technical and environmental challenges in monetising hydrocarbon potential of gas hydrates globally?

Basically, there are four technologies - 1) Thermal Stimulation, where the temperature is increased above the hydrate stability region; 2) Depressurisation, where the pressure is decreased below the hydrate stability region; as it was used in Mallik well; 3) Chemical Injection of Inhibitors, where the temperature and pressure conditions for hydrate stability are shifted; and 4) CO 2 or mixed CO 2 and N 2 exchange, where CO 2 and N 2 replace CH 4 in the hydrate structure.

There are three major issues in terms of environmental concerns in exploiting methane from gas hydrates. One is leakage or emission of methane while exploiting gas hydrates, which will enhance the methane concentrations in the atmosphere. Being a strong greenhouse gas (~20 times stronger than CO 2), enhanced methane flux to atmosphere can contribute to global warming. As our Arctic region is full of methane under the frozen soil cover (permafrost) and ice, there is a concern over uncontrolled release of methane from hydrate formations due to melting of ice prompted by global warming and further increase in atmospheric methane flux.

Other issue is that the thawing of hydrates during exploitation may release large amount of water destabilising the sediment reservoir. Destabilisation may cause damage to establishments as well as trigger slides or sediment massflow which may lead to Tsunami like situation.

Additional thing is that drilling and use of chemicals to exploit gas hydrates could impact the benthic biota or living organisms in the marine environment, which is a cause of worry among marine ecologists worldwide.

As the exploration & exploitation of gas hydrates is currently in nascent stage, what are the roles of R&D before going for that, especially in Indian context?

Potential ecological and environmental risks to develop & monetise gas hydrates are being flagged by many experts and geologists. The considerable rewards of releasing methane from gas hydrate fields must therefore be balanced with risks, and more research may be required to determine the likelihood of such risks materialising and whether there are ways of mitigating them.

Research & Development (R&D) for successfully monetising the unconventional hydrocarbon is going on worldwide. India has been involved in gas hydrates research since 1997. The CSIR-National Institute of Oceanography (NIO) is actively involved in the gas hydrate exploration programme from the inception of National

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INTERVIEW Gas Hydrate Programmes (NGHP) under the aegis of Directorate of gas and hydrocarbon (DGH). NIO participated in the NGHP expedition I&II. Ministry of Earth Sciences has also funded NIO’s hydrate research programme. NIO has also carried out extensive research on hydrate geology and geophysics in the K-G and Mahanadi basins and prepared the first hydrate stability zone thickness map.

CSIR-National Geophysical Research Institute (CSIR-NGRI) and National Institute of Ocean Technology (NIOT) are also actively involved in hydrate exploration programme in the geophysical studies and technology development.

India has the complete scientific know-how of gas hydrates reserves and their potential but we don’t have the proven technology. Countries like USA, China and Japan with their current R&D capabilities have the position to develop viable, sustainable and economical feasible technology to explore gas hydrates but India has not reached to that level. Hence we may have to outsource the technology.

NGHP Expedition-I was more or less outsourced to US Geological Survey (USGS) and NGHP Expedition-II was completely outsourced to Japan Oil, Gas and Metals National Corporation (JOGMEC). The reason is that we don’t have the drilling ships like JOIDES resolution and Chikyu to fully explore the potential of gas hydrates in Indian Basins. In NGHP Expedition-I in 2006, we used JOIDES Resolution Drilling Ship and NGHP Expedition-II, we used Chikyu ship of JAMSTEC. Can you brief us the policy framework and government’s initiatives for developing gas hydrates in the country?

Unlike conventional gas & hydrocarbon, which has a very strong policy, the gas hydrates research & exploration in India is still at a nascent stage so we don’t have the well-defined policy framework.

In National Gas Hydrates Program (NGHP) in 2015, the government spent around ` 616 crore. Prior to that in NGHP leg 1 in 2006, the government spent almost ` 150 crore. The cost escalated significantly. It will take some time before we enter into deepwater exploration like Mahanadi and Andaman for more detail analyses. The collaborations with USA and Japan were for the exploration part of gas hydrates. So far we have not carried out any pilot scale exploitation/production testing in our basins. Pilot scale of exploitation is necessary to find out whether the gas can be sustainably taken out from Indian basins or not. It is extremely important for the success of the hydrate programme to involve multiple research organisations and scientists with proven skill in hydrate research in the exploration programme. This will help India to become self-reliant and reduce the dependency on other countries for exploration programme.

With the current plunging global oil price, according to you is it the right time to invest in gas hydrates?

Yes, it is the right time to invest in gas hydrates to develop the right technology, know the reserves, economic feasibility, etc. For example, the current plunging oil price is due to the Shale gas revolution of USA and OPEC oil glut. But it will not be continued for ever and I am sure that in the next 30-40 years, the potential of global conventional hydrocarbon will certainly be going down. So countries like India, China and Japan – who have reduced substantially their oil & gas import bills due to the current plunging oil price, should invest in pilot scale of exploration & exploitation of gas hydrates. www.oswindia.com

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Offshore World | 18 | October - November 2015

GUEST COLUMN

COMING IN FROM THE COLD? IRAN’S ENERGY SECTOR GEARS UP FOR POST-SANCTIONS ERA The final comprehensive deal agreed in Vienna in July on the controversial nuclear programme between Tehran and a group of world powers comprising the five permanent UN Security Council members Britain, France, Russia, China and the US plus Germany (P5+1) would pave the way for Iran to return as a major oil exporter and provide much-needed stimulus to the Islamic Republic’s ailing domestic economy, says Thangapandian Srinivasalu, Executive Director, GP Group. Although there can be little doubt that interest among international firms in developing Iran’s hydrocarbon resources post sanctions is enormous, certainly, the risks and challenges associated with becoming involved in Iran’s energy sector would still be large – but likely to offer sufficient upside to attract international interest, he firmly believes.

A

fter years of isolation, Iran is positioning itself for the lifting of international sanctions, a move that would revive the Islamic Republic’s ailing energy industry, pave the way for its return as a major oil exporter and provide much-needed stimulus to the domestic economy.

Following the final comprehensive deal agreed in Vienna in July on the controversial nuclear programme between Tehran and a group of world powers comprising the five permanent UN Security Council members Britain, France, Russia, China and the US plus Germany (P5+1), Iran may see relations with the rest of the world start to return to normal as early as 2016. This development would not only reverse the fortunes of its struggling economy; it would also open the biggest bonanza for international energy companies since the 2003 ouster of Saddam Hussein in neighboring Iraq.

Iran, holder of the world’s fourth-largest proved oil and the second-largest proved natural gas reserves, has been hard hit by UN and international bilateral sanctions imposed on the country in 2006 and 2010 on top of existing US sanctions. But it was the latest set of even more stringent measures enacted by the US and the European Union (EU) in late 2011 and 2012 that had the most devastating impact on the local economy.

Source: www.tradingeconomics.com | Central Bank of Iran www.oswindia.com

Today, Iran’s conventional proved oil reserves stand at 157 billion barrels. The country has 10 refineries, extensive pipeline networks, oil terminals and ports along the Gulf coast, and a large petrochemicals industry.

According to the International Monetary Fund, the sanctions have had a contractionary impact on the economy, with real gross domestic product (GDP) declining by almost 6 per cent in 2012/13. During the first half of 2013/14, real GDP was estimated to have declined by about 2.5 per cent, compared with the same period in the previous year. Between June 2012 and February 2014, Iran recorded negative GDP growth for seven consecutive quarters.

Source: www.tradingeconomics.com | US Energy Information Administration Offshore World | 20 | October - November 2015

MARKETING INITIATIVE Aimed at drawing more foreign companies to invest in and develop Iranian hydrocarbon reservoirs, the new, so-called Iran Petroleum Contract (IPC) is still being finalised but indications are that it will be a major improvement on the old buyback model.

With more than 100 years of experience, Iran has one of the world’s most mature oil sectors and the energy infrastructure that has been built up since is extensive.

Today, Iran’s conventional proved oil reserves stand at 157 billion barrels. The country has 10 refineries, extensive pipeline networks, oil terminals and ports along the Gulf coast, and a large petrochemicals industry.

Several large refinery upgrades were stopped in their tracks when sanctions hit, which could present International oil services companies with the opportunities to win contracts worth tens of billions to repair and modernise Iran’s oil refineries once sanctions are removed. Iranian Petroleum Minister Bijan Zangeneh recently said that the Islamic Republic planned to invest USD 80 billion over the next 10 years to upgrade and expand its petrochemical sector.

Few would disagree that Iran has the potential to reclaim its status as an energy giant. But it won’t be an easy task. The sector’s infrastructure is in dire need of rehabilitation and upgrading worth tens of billions of dollars after years of underinvestment.

With hopes high that the sanctions on Iran will start to be lifted over the coming months now that US President Barack Obama has secured the support he needs to ensure the accord will not fail in the US Congress, technocrat Zanganeh will move swiftly to finalise the framework of a new oil contract model that will replace the unpopular buyback schemes. Aimed at drawing more foreign companies to invest in and develop Iranian hydrocarbon reservoirs, the new, so-called Iran Petroleum Contract (IPC) is still being finalised but indications are that it will be a major improvement on the old buyback model and will be unveiled at the Iran Oil & Gas Summit in London this December.

The IPC is set to replace the traditional buyback scheme, which was first introduced in the 1990s in an attempt to bridge the gap between the country’s need to attract foreign oil and gas investors, and a ban on private and foreign private ownership of natural resources under the Islamic republic’s constitution. They are essentially risk service contracts, under which the contractor is paid back by being allocated a portion of the hydrocarbons produced as a result of providing services.

Mohsen Shoar, Managing Director at Dubai-based Continental Energy DMCC and an expert on Iranian energy, says the new IPC model varies markedly from the existing buyback schemes in that it proposes the establishment of a joint venture between NIOC (or one of its subsidiaries) and a foreign partner for field exploration, appraisal, development and—for the first time since 1979—production.

The IPC is also designed to take advantage of foreign companies’ marketing expertise and give Iran access to their supply network to find an export market. This is important at this time as the global energy market is expected to face oversupply in the mid-term due mainly to the discovery and harnessing of shale gas in North America. Thus, having the assistance of an international company and its networks around the globe will become an increasingly important resource for Iran.

“I would also expect strong Chinese and Indian interest,” says Shoar, adding that ultimately energy companies across the board are likely to seek involvement. “Iran needs huge investments and the potential for rewards is huge, especially in the longer term. There is, for example, a lot of stranded and non-associated gas in Iran, so there is a lot of potential for gas projects in the form LNG and pipelines for example.”

Despite the recent history of sanctions and the withdrawal of Western IOCs such as Shell, Total, Statoil and Repsol, Iran has sought and secured expertise and financing from willing Eastern firms.

In 2013, Iran cancelled CNPC’s (China National Petroleum Corporation) contract to develop Phase 11 of the South Pars natural gas field, also over persistent delays. And, in the same year, it reportedly awarded the development of the ONGC Videsh Ltd (OVL)-led Farsi gas block to a local company after the Indian state-run consortium dragged its feet on operating the project.

Source: Oil & Gas Journal

There can be little doubt that interest among international firms in developing Iran’s hydrocarbon resources post sanctions is enormous. To be sure, the risks and challenges associated with becoming involved in Iran’s energy sector would still be large – but likely to offer sufficient upside to attract international interest.

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FEATURES

DEVELOPMENT OF SOUR GAS TREATMENT IN INDIAN OFFSHORE FIELD Acid gas sweetening units are used to remove the Hydrogen Sulphide (H 2S) and Carbon Dioxide (CO 2) which comes with associated gases obtained from offshore oil & gas field. Acid Gas Removal Unit (AGRU) uses 30-35 per cent concentration of Methyldiethanol Amine (MDEA) solution for absorption of H 2S and also CO 2 till certain limit. Indian offshore is having sour field in Heera-Panna Bassien block of Bombay offshore, about 60-90 km towards west coast of Mumbai. These fields are of marginal nature having high H 2S & moderate CO 2 content. Due to unavailability of sour gas treatment facilities at offshore, it was not possible to exploit these sour fields (as transportation of sour gases is economically not feasible and also not recommended considering HSE factors). As the concentration of H 2S is high (upto 28000 volppm) in associated gas, it is also not possible to release such high concentrated acid gas in atmosphere which separates during regeneration of amine.

To overcome such a problem, Acid Gas Disposal Unit (AGDU) is used in offshore platforms to incinerate H 2S gas converting into SO 2, which is then scrubbed in seawater scrubber (with constant caustic dosing) to avoid emission of toxic gases in the atmosphere. The Gas Sweetening Unit (GSU) unit with above specification was successfully commissioned for the first time in Indian offshore by our team. Being first system of this kind, many problems occurred during commissioning and start-up.

In this present paper, we are also going to discuss the problems faced during commissioning phase with their solutions. Also safe commissioning guidelines are mentioned.

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ecent years have demonstrated that for an increasing number of countries it may be difficult to meet their future local gas demand and gas export commitments [1]. India is the 13 th largest consumer of natural gas in the world and domestic demand is increasing due to increasing population, higher living standards and development of new energy intensive industries such as Petrochemical, Metal Smelters etc. Additionally gas injection is applied more frequently to boost the life time of oil producing fields. In order to fulfill the future gas demands, resource owners are forced to develop more complex gas fields like sour gas fields which were previously regarded as economically unattractive.

Figure 1.1 shows the increase in gas demand and supply over past few years.

The development of a sour gas field has many challenges, not only Health, Safety and Environmental (HSE) aspects, which need to be reflected in the design of the surface facilities, but also challenges related to the continuous drive to minimise the environmental footprint from the surface facilities.

This results in stringent Sulfur Dioxide (SO 2) emission targets and corresponding ultra-high Sulphur Recovery Efficiency (SRE) requirements. In order to meet these requirements, sophisticated technologies need to be applied to develop sour gas fields [3]. These challenges are combined with high availability targets, large uncertainties in feed gas compositions, fluctuating and limited availability of skilled labour for construction.

A key aspect of sour gas field development is the selection of the disposal method for sulphur containing molecules. From a cost perspective, reinjection of sour gas molecules back into a field can be an attractive option. This is typically only acceptable when empty and disconnected fields are available in close surroundings. This removes the risk of field contamination which needs to be avoided to meet the sour gas field life time. For this reason, sour gas reinjection is not widely applied in the industry [3].

Figure 1.1: Domestic demand and supply Projection of gas in India (in MMSCMD) www.oswindia.com

India has sour gas fields at Mumbai offshore Bassein region, called as B series marginal fields. These fields are of marginal nature, with high H 2S and moderate CO 2 content. ONGC Ltd has recently implemented sour gas treatment facilities in this region so as to utilise these sour fields, this is India’s first offshore facility to have sour gas treatment unit along with an acid gas disposal unit. This facility was commissioned in June 2014, which is taken as a case study in this paper.

Increasing energy costs and growing demand for natural gas have driven the development of sour gas fields around the world. About 40 per cent of the world’s

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FEATURES natural gas reserves are in the form of sour gas where H 2S and CO 2 compositions exceed 10 per cent volumetric of the raw produced acid gas. In some cases, the acid gas composition in these reserves is very high and economics of producing pipe line quality gas are marginal.

Sour Gas Treatment (Acid Gas Removal Process) There are many treating processes available. However, no single process is ideal for all applications. The initial selection of a particular process may be based on feed parameters such as composition, pressure, temperature, and the nature of the impurities, as well as product specifications. The second selection of a particular process may be based on acid/sour gas percent in the feed, whether all CO 2, all H 2S, or mixed and in what proportion, if CO 2 is significant and reduction of amine unit regeneration duty [4].

Acid Gas Processing/Disposal Methods Acid gas leaving from gas sweetening unit (Figure 2.1) contains very high concentration of H 2S and CO 2 gases which are very harmful for environment and human health. This waste gas can be sent for further processing to recover elemental sulfur, to produce some other useful industrial products such as sulphuric acid or it can be sent to a disposal unit.

Final selection is ultimately based on process economics, reliability, versatility, and environmental constraints. Clearly, the selection procedure is not a trivial matter and any tools that provides are liable mechanism for process design is highly desirable [4].

Available gas sweetening processes [9]: • Chemisorption with regenerative solvent (using amines, glycol amines, K 2CO 3 etc) • Non-regenerative chemical process (scavenger process) • Molecular sieves • Dry sweetening process (Iron Sponge:Iron Oxide) Chemisorption with regenerative solvent is most widely used process for sweetening of sour gas in refineries as well as offshore facilities. Chemical solvents react with the acid gas components to form loosely-bonded chemical complexes.

On heating at reduced pressure, these complexes dissociate and release the acid gas from the solvent.The choice of solvent is based on the gas composition, expected sweet gas specifications, requirements of the acid gas processing unit, etc. Figure 2.1 shows a typical chemisorption type sour gas sweetening process.

The most widely used chemical solvents for the removal of acid gases from natural gas streams are alkanolamines (referred to generally as amine solvents), employed as aqueous solutions. These chemical solvent processes are particularly applicable when acid gas partial pressures are low and/or low levels of acid gas are desired in the residue gas. Because of the low hydrocarbon solubility in the aqueous solution, these processes are particularly effective for treating gases rich in heavier hydrocarbons. Some alkanolamines can be used to selectively remove H 2S in the presence of CO 2.

The basic chemical reactions involved in this process are as follows:

Figure 2.1: Typical chemisorption gas sweetening process

Below are the processes which can be used depending upon the requirement and economic factors: 3.1 Sulphur Recovery Unit (SRU) 3.2 Wet Sulphuric Acid Process (WSA) 3.3 Reinjection in Wells 3.4 Acid Gas Disposal Unit (AGDU)/ Seawater Scrubbing process 3.1 Sulfur Recovery Unit (Claus Process): The Claus process is the most significant gas desulphurising process, recovering elemental sulphur from gaseous hydrogen sulphide. H 2S removed in the gas sweetening process is sent to the sulphur recovery unit (SRU) as acid gas. SRU recovers H 2S as elemental sulphur through the Claus reaction.

Reactions occur in two stages: Flame reaction stage or thermal stage:

Catalytic reaction stage:

Offshore sulphur recovery was considered as an alternative for acid gas handling.

After preliminary review of the option, it was determined that it was not economically feasible due to the size of the platform required for the process and the logistics of handling the sulphur product.

Where R denotes an alkanol group and R’ and R’’ can be alkyl or alkanol groups, hydrogen, or a mixture of the two depending on whether the amine is primary, secondary or tertiary. H 2S & CO 2 are termed as acid gases.

3.2 Wet Sulphuric Acid Process (WSA): The wet sulphuric acid process (WSA process) is one of the key gas desulphurization processes on the market today. Since the Danish catalyst

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FEATURES company Haldor Topsoe introduced and patented this technology in the late 1980s, it has been recognised as an efficient process for recovering sulphur from acid gas in the form of commercial quality Sulphuric Acid (H 2SO 4), with simultaneous production of high pressure steam. Figure 3.2.1 shows basic flow of a WSA process.

wet sulphuric acid process; in this process acid gas from regenerative solvent type gas sweetening unit, is sent to an incinerator operating at temperature 760830°C, to convert it to a mixture of SO 2, H 2O (vap) & SO 3 in presence excess of air.

The flue gas flows downward through a refractory lined nozzle with a Venturi shaped quencher (evaporative cooler). The gas expands and flows past a high pressure spray into the quencher where it encounters further liquid contact to be cooled to its dew point. The flue gas is saturated with water vapor which causes it to cool down to its adiabatic saturation temperature. Saturated flue gas from the quench venturi is next ducted to the seawater SO 2 scrubber. SO 2 scrubber consists of two different sections (seawater scrubber & caustic scrubber) to ensure complete absorption of toxic gases viz. SO2, SO 3, H 2S & CO 2. Lower section is called seawater scrubber where flue gas is brought in contact counter-currently with seawater, this section removes upto 95 per cent of toxic gases. Upper section of SO 2 scrubber is called caustic scrubber where aqueous solution of NaOH is dosed to absorb remaining toxic gases exiting from seawater scrubber section, this ensure 98 per cent removal of toxic gases from flue gas.The cleaned flue gas passes through a demister pad and is ducted to the atmosphere through an extended portion of ducting. The stack is mounted directly above the caustic scrubber. NaOH also helps to neutralise the acids formed in absorption process.

Figure 3.2.1: Block diagram of Wet sulphuric acid process (WSA)

The main reactions in the WSA process [5]:

Reaction taking place in SO 2 scrubber: Effluent discharge from scrubber bottom majorly contains acids and sodium

Again this method is not economically feasible for offshore facilities due to the size of platform required. Also health and safety concerns are very high due to handling and transportation of acid. WSA process is most suitable for refineries and onshore facilities only.

3.3 Reinjection in Wells: One other approach to avoid acid gas emission to atmosphere is by injecting it to an empty field which is nearby. Acid gas re-injection is attracting much attention as an environmentally-sound and cost-effectiveapproach that can avoid the cost of traditional H 2S processing and the problems of handling theelemental sulphur product, particularly for very sour natural gas streams. In this process, the acid gasesseparated are compressed and injected into the disposal reservoir through a special well, in amanner similar to the disposal of produced water. The disposal zone can be either ahydrocarbon reservoir or a saline aquifer [2].

salts. Approximate pH turns out to be around 2-3 which exceeds allowable limits of effluent discharge. To overcome this problem an Effluent neutralisation unit (ENU) is installed. ENU consists of a static mixer where effluent discharge stream is diluted with large quantity of seawater to maintain the pH up-to allowable limit and then it is discharge to sea. Figure 3.4.1 shows basic block diagram of seawater scrubbing process.

By far this method is considered best for disposal of acid gas as it reduces chance of emission of toxics in environment but this method is economically not feasible (as it cannot be applied to facilities with high amount of acid gas and also it is not suitable for long time operation) andit also has some other limitations such as, we must have an empty or disconnected field nearby to avoid contamination in field, high risk & safety factors as we are dealing with high pressure acid gas.

Hence this method is not widely used in most of the industries.

3.4 Acid Gas Disposal Unit (AGDU)/Seawater Scrubbing Process: Acid gas disposal unit or seawater scrubbing process is quite similar to that of www.oswindia.com

Figure 3.4.1: PFD of Seawater scrubbing process

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FEATURES Process Advantages: This process has many advantages over other conventional acid gas processing & disposal techniques for offshore facilities.

• This is a very simple process.

• The plant is highly reliable because of its simplicity.

• SO 2 is washed out of the flue gas in a once-through operation, i.e., there will not be any clogging problems.

• This is very compact unit, so platform size is not an issue.

• There are no critical levels or other process parameters to control.

• No expensive chemicals are required.

• The process uses only seawater and air, hence operating costs is low.

• No land disposal is needed.

• The absorbed SO 2 is converted to sulphates, a natural constituent of seawater.

This is considered safe for aquatic life.

• It is a safe choice.

Economical Impact In India, supply and demand gap of oil & gas are gradually increasing every year, which results increase in market value of this commodities.India’s demand for oil and gas has been increasing significantly in recent years boosted by its rapid economic growth. By 2013, India had become the world’s fourth largest oil consumer, consuming 3.7 million barrels a day (mb/d). It is forecast to reach 4.4 mb/dby 2018, when it will overtake Japan as the third largest consumer of oil. This growthin oil demand has also made India the fourth largest oil importer since 2011, importingaround 3.5 mb/d of crude. India’s limited oil production has been slowly declining andis expected to continue declining, thereby increasing its dependence on imports andallaying its concerns over energy security[15]. One of the solutions to overcome this declining behavior is to exploit the sour fields present in offshore locations.

Nearly 40 per cent of the world’s gas reserves contain sour gas that poses obstacles to development. Overcoming those obstacles is a key challenge for oil companies. B&S region of Mumbai offshore is having many sour fields; these fields are of marginal nature with high H 2S and moderate CO 2 concentration. Due to unavailability of sour gas treatment facilities at offshore, it was not possible to exploit these sour fields (as transportation of sour gases is economically not feasible and also not recommended considering HSE factors). First Indian offshore facility with sour gas treatment and acid gas disposal (AGDU) units was commissioned at Mumbai offshore in 2014 by us; giving an opportunity to ONGC to exploit these sour fields. It has a great impact on economics and it helps us reducing supply and demand gap.

India’s first platform with sour gas treatment units is designed to handle 25000 BOPD and 1.1 MMSCMD natural gases; it’s in operation from last 18 months.

Considering 70 per cent capacity of operation below is a workout to show the impact on economics: Oil production/day on 60% capacity = 0.7*25000 = 17500 BOPD Total production in 18 months

= 17500*18*30 = 9.45*106 Barrels

Gas production/day on 60% capacity = 0.7*1.1 = 0.77 MMSCMD

Total Gas production in 18 months = 0.77*18*30 = 415.8 MMSCM Thus, using this technology it was possible to achieve above mentioned production of oil & gas. And there is more potential in these fields.

CASE STUDY The following case study is used to demonstrate the effectiveness of sour gas treatment units at offshore facilities.

The case study is taken of India’s very first offshore platform with gas sweetening unit and acid gas disposal unit (AGDU); it has regenerative solvent type sour gas sweetening process and SO 2 seawater scrubbing process for acid gas disposal.

This offshore platform is located in B&S region of Mumbai offshore which belongs to ONGC Ltd.; this field is having 28000 ppm of H 2S concentration and 7-8 vol% of CO 2.

This offshore platform was commissioned by UPCEM Engineering & Consultancy Pvt Ltd in 2014. With addition of sour gas processing units this platform became more complicated than normal offshore platforms. Commissioning of this platform was a challenging job because of sour environment and non-awareness of acid gas disposal unit in Indian offshore.

Below mentioned are the problems faced during commissioning of acid gas disposal unit (AGDU): • Air Fuel Ratio Adjustment in Incinerator: Maintaining air to fuel ratio in incinerator was quite a difficult task which ultimately affects the temperature of incinerator and can cause process shutdown. Calorific value of H2S gas is very high hence it plays important role sudden rise of incinerator temperature, thus control philosophy allows more quench air into incinerator. Also there was no moisture monitoring or removal unit for combustion air; it also has an impact on incinerator temperature which ultimately disturbs air/fuel ratio (as air/fuel ratio was controlled by temperature in control philosophy).

• Damages in Expansion Bellow: Thermal shock across the quench venturi is very high and to avoid any kind of expansion in metallic part a fabric expansion bellow is installed. This bellow helps compensate all kind of expansions and contractions taking place inside the system. Due to improper design of this expansion bellow it was unable to withstand such high a thermal shock and got damaged; which was a very risky situation. Better designed quality expansion bellow was then installed to overcome this problem.

• Equipment Failure: Many equipment failures occurred due to non-awareness of such kind of system at Indian offshore, such as burner, blowers, high flow submersible pumps, expansion bellow etc. But with expertise knowledge and extended commissioning experience of UPCEM, these problems were rectified and tackled easily.

• Non-availability of pH Control: Effluent discharge from acid gas disposal unit (AGDU) contains very high amount of sulphates, and according to environmental norms effluent discharge should be of pH 7-8. But there was no online pH monitoring system was available for continuous monitoring of effluent

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FEATURES quality. This modification needs to be implemented to avoid any acidic effluent release to the sea which can be very dangerous to aquatic life as well as it can cause corrosion on platform legs.

Health & Safety Guidelines during Commissioning Hydrogen Sulphide or acid gas (H 2S) is a flammable, colorless gas that is toxic at extremely low concentrations. It is heavier than air, and may accumulate in low-lying areas. It smells like ‘rotten eggs’ at low concentrations and causes you to quickly lose your sense of smell. Many areas where the gas is found have been identified, but pockets of the gas can occur anywhere.

Commissioning is a complex and sophisticated technical specialty, which may be considered as a specific and independent engineering discipline, as important as the more traditional ones; it requires sharp skills, vast knowledge and good experience. Commissioning of a sour gas handling platform can be a difficult task because it involves very high risk of Health Safety and Environment (HSE).

Many accidents takes place during commissioning phase due lack of knowledge and non-seriousness of the situation, but due to UPCEM’s extensive experience in commissioning field, India’s very first sour gas handling platform was commissioned with zero accident rate.

Below are some guidelines which are to be strictly followed for safe commissioning of a sour gas field: • Skilled Manpower: It is absolutely necessary to have skilled manpower for sour field jobs and every individual should have awareness about H 2S gas hazard and they must go through H 2S safety training.

• Personal Protective Equipment (PPE): Every personnel entering H 2S zone must wear personal protective equipment such as self-contained breathing apparatus, safety goggles, safety gloves, safety shoes, safety helmet etc. all the time.

• Detectors: Every individual must carry a H 2S detector with him while working in H 2S areas. And also H 2S detectors need to be installed at different locations on platform with F&G system.

• PTW: Special permits needs to be taken to work in H 2S zone where a safety officer should analyze all the risk. These type of permits fall under confined space permit category.

• Medical Emergency Team: Emergency medical team should always be there with the team working in H 2S. • Evacuation Plan: Evacuation plan should be ready in case of H 2S leak and every member should be informed about the plan.

• H 2S Muster Area at Elevation: Muster station for H 2S leakage should be defined and as H 2S is heavier than air, muster station has to be on an elevation.

• Daily toolbox meeting to be carried out.

• Induction training about H 2S safety needs to be conducted periodically.

• Standard Procedure to be followed for particular task.

• Risk Assessment/Hazard Analysis report to be made before starting the task.

• All personnel should be aware of the H 2S safe shelters available on platform.

commissioned. This technique helps us reducing the supply & demand gap by utilizing sour fields. It has also given exposure to Indian people about this technology thus increasing individual competency in international market.

Therefore, this technique should be implemented in other sour fields as we have experienced many advantages on economy, personnel development, environment etc. As this technology is new in Indian offshore, further improvements are also in process.

(The authors would like to acknowledge M/s Sime Darby Sdn Bhd and M/s ONGC Ltd for providing us the opportunity to commission this platform.)

References 1. Energy Information Agency (2014).

2. Encyclopedia of Hydrocarbons, New Developments: Energy, Transport, SustainabilityVolume III 3. M. Gierman, P. Micone, V. Leveille, Sour-to-Acid concept for sour gas fields, Sour Gas Field Development, June-2014.

4. Mahin Rameshni, P.E., Technical Director, Sulfur Technology and Gas Processing, WorleyParsons, Strategies for Sour Gas Field Developments 5. H. Rosenberg, Haldor Topsoe A/S, Lyngby, Denmark, Topsoe, Wet gas sulphuric acid (WSA) technology-anattractive alternative for reduction of sulphur emissions from furnaces and converters, The Southern African Institute of Mining and Metallurgy, 2006.

6. Deep Panuke Offshore gas development Volume 2, EnCana Corporation, November 2006.

7. Goran B. G. Nyman, Arvid Tokerud, ABB Flakt, Oslo, Seawater Scrubbing Removes SO2 from Refinery Flue Gases 8. G.K Sarda, Natural Gas: Present Scenario & Future Prospects, Raw material & Fuel Sub-committee 9. Sour Gas Sweetening, Petrowiki, http://petrowiki.org/Sour_gas_sweetening 10. Current Environmental Issues and Challenges by Giacomo Cao, Roberto Orrù, 2014.

11. John J. Carroll, James R. Maddock, Gas Liquids Engineering Ltd., Design Considerations for Acid Gas Injection, Laurance Reid Gas Conditioning Conference, Feb 1999.

12. Pam Boschee, Taking on the Technical Challenges of Sour Gas Processing, Oil& Gas Facilities, December 2014.

13. Acid and Sour Gas Treating Processes by Stephen A. Newman, 1985.

14. Acid Gas Injection and Related Technologies by Ying Wu, John J. Carroll, 2011.

15. ENERGY SUPPLY SECURITY 2014, PART 3.

Conclusion Case study of India’s first offshore platform with sour gas treatment facility has demonstrated that the challenging opportunity was accepted and successfully www.oswindia.com

Offshore World | 26 | October - November 2015

Mehtab Shaikh Managing Director UPCEM Engineering & Consultancy Pvt Ltd Email: upcem.consultancy@gmail.com V K Gajinkar Head - Process & Commissioning UPCEM Engineering & Consultancy Pvt Ltd Email: upcem.gajinkar@gmail.com Amjad Khan Process & Commissioning Engineer UPCEM Engineering & Consultancy Pvt Ltd Email: upcem.amjad@gmail.com Melwin Raj Process & Commissioning Engineer UPCEM Engineering & Consultancy Pvt Ltd Email: melwin@upcem.com

FEATURES

EARLY PRODUCTION PREDICTION FOR UNCONVENTIONAL WELLS While oilfield service companies have been claiming the ability to predict unconventional well production using reservoir models, the claim may be true in the sense that they can predict production – just not very accurate. The article presents a solution that enabled reservoir models to incorporate concrete data about each fracture, precisely calibrating the model to the hydraulically fractured state of the reservoir, resulted in a model that accurately predicted production in a blind test.

F

or years, oilfield service companies have been claiming the ability to predict unconventional well production using reservoir models. The claim is true; they can predict production – just not very accurately. And operators know it.

“Everyone has a reservoir model; but the models are not very reliable at predicting detailed production,” says Casey Lipp, Geologist at Peregrine Petroleum. The main reason for this unreliability is the inability of the models to simulate variable fractures. Current models have to assume that all fractures along a wellbore are planar and simple, with the same height, length, and permeability. Using such simple fracture models in a reservoir simulation multiplies the inaccuracies of these assumptions.

In a case study with Peregrine Petroleum, MicroSeismic presented a solution that enabled reservoir models to incorporate concrete data about each fracture, precisely calibrating the model to the hydraulically fractured state of the reservoir.

This resulted in a model that accurately predicted production in a blind test.

“When Peregrine began working with MicroSeismic, we became very interested in the option of adding microseismically-derived fractures into the reservoir model.

Incorporating precise fracture data appears to have achieved a meaningful leap in the ability to accurately predict production,” said Lipp.

Better Model Variables Earlier reservoir models have failed to account for the variability of proppant placement throughout the fractures in the Stimulated Rock Volume (SRV). Because of this gap, the reservoir models failed to find a useful correlation between SRV and cumulative production over time. MicroSeismic’s concept of Productive Stimulated Rock Volume (P-SRV) is able to fill this gap by differentiating between proppant-filled vs un-propped fractures. P-SRV has shown much closer correlation to cumulative production than was ever achieved with total SRV. P-SRV is able to define what portion of the stimulated fracture network will be productive.

But how productive will the P-SRV be? The most reliable indicator of a fractured reservoir’s production is the level of permeability enhancement achieved by the hydraulic stimulation. When a reservoir is hydraulically fractured, the basic goal is to enhance the permeability of the reservoir by inducing new fractures and activating the existing natural fractures.

The process for determining the reservoir’s P-SRV and permeability enhancement involves building a deterministic discrete fracture network (DFN) model: www.oswindia.com

1. A fracture plane is defined for every viable microseismic event, including the fracture size and orientation.

2. The distribution of proppant throughout the fractures is determined using the actual amount of proppant pumped for each stage.

3. A geocellular grid is superimposed on the DFN to obtain the SRV and P-SRV, capturing the proppant-filled rock volume.

Figure 1: Computing permeability tensor.

One key advantage of this workflow is the ability to capture the fracture intensity (fracture number, orientation, and aperture) achieved in each cell of the geocellular grid, which enables quantification of the permeability enhancement in each cell. Figure 1 shows an example of the P-SRV with the permeability enhancement calculation process for one geocell.

This information fundamentally changes the resulting reservoir model because it enables the model to be based on a deterministic DFN model, incorporating actual changes in the fracture intensity along the wellbore; whereas past reservoir models could only use a theoretical fracture model that assumed every fracture along the wellbore was the same simple fracture.

History-matching for Precise Calibration Unconventional reservoir models are often calibrated by history-matching the results with production data from an already-produced well. Theoretical models are typically derived from a rate-transient analysis or decline-curve analysis.

These theoretical models can be useful for predicting a completed well’s total estimated ultimate recovery (EUR), but they are not able to accurately predict production over shorter increments of time or predict how the reservoir will drain as the well continues to be produced. The greatest advantage of the deterministic DFN/reservoir model is its ability to accurately predict the volume

Offshore World | 28 | October - November 2015

FEATURES and pattern of reservoir drainage over time and, therefore, predict incremental production over time.

The deterministic reservoir model incorporates the permeability enhancement values from the DFN along with the other typical model variables such as microseismic data, pressure-volume-temperature data, and core and petrophysical data from well logs. History-matching of existing production data from a single produced well is used to calibrate the permeability enhancement values from relative levels of permeability into absolute permeability values.

The calibration’s resulting mathematical multiplier can then be applied to the microseismic data of multiple nearby unproduced wells to automatically provide absolute permeability values for those wells. This means that absolute production volumes can be accurately predicted for each nearby unproduced well.

This process enables reservoir models to be precisely calibrated to the current state of the reservoir, based on mathematically-derived data, rather than calibrating based on theoretical assumptions. The result is a reservoir model that is calibrated so accurately, it can dependably predict short- and long-term production and reservoir drainage for multiple monitored wells using the same absolute permeability multiplier that was already determined during history-matching.

Uses Reservoir models that incorporate these deterministic DFNs and absolute permeability values enable an operator to see how the reservoir is expected to drain as each nearby well is produced. Understanding the reservoir drainage pattern of each well can prevent incorrect spacing of wells, which results in wells competing for the same drainage volume (if spaced too close together) or leaves significant volumes of rock undrained (if spaced too far apart). Predicting accurate reservoir drainage patterns also enables optimisation of other variables of field development, such as stage spacing, clustering, or refracturing, to maximise net present value. Production timelines or economic thresholds can be used to constrain long- or short-term field plans, depending upon whether the operator wants to maximise short-term production or wait for the long term.

These decisions are often based on current economic conditions.

Quantifying the absolute permeability of each geocell in the reservoir also enables quantification of the productivity of each cell. This could indicate reservoir sweet spots and measure the success of treatment methods for different stages. Stages that are predicted to be less productive can be used to indicate improvements for future treatments, without waiting for the well’s production data to come in.

After processing the production data from one nearby produced well, reservoir models for subsequent monitored wells are available nearly immediately. The same absolute permeability multiplier can immediately be plugged into each well’s microseismic data to predict production for multiple nearby unproduced wells, rather than waiting for each well’s production data to calibrate each model.

Operators would typically have to wait at least six months to gather enough production data for each well’s separate model calibration. Eliminating this wait-time enables an operator to assess the expected production for multiple area wells and use that information to plan ahead for future development. It also negates the workflow and time that would typically be required to calibrate each reservoir model.

CASE STUDY Introduction In 2014, Peregrine Petroleum was rapidly drilling and completing wells in Ellis County, Oklahoma, targeting the Cleveland formation. In this area, the incised, valley-filled depositional environment makes for highly variable geology and poses challenges in determining optimum treatment design and well spacing.

MicroSeismic, Inc partnered with Peregrine to help them quantify fracture geometry and improve well spacing, stage length, and completions parameters.

Peregrine asked MicroSeismic to use their proprietary deterministic reservoir modeling method to prove in a blind test that the model could accurately predict production of a monitored well (i.e., Well B), if Peregrine provided production information from one nearby already-produced sample well (i.e., Well A).

Background Wells A and B were drilled in the early Missourian Cleveland formation, which produces natural gas and oil at a depth of approximately 9,200 ft true vertical depth (TVD). The regional geological structure is a homoclinal dip to the south with a few subtle structures. The project area reservoir is interpreted as being dominated by low-permeability tidal-shelf and distal delta-front deposits. These lenticular sand bodies make it difficult to predict the size and distribution of the reservoir and, therefore, the potential per-well reserves.

With a temporary surface array, MicroSeismic captured data on 20 stages.

Peregrine provided surface pressure and production information for Well A. Using the microseismic and client-provided data, MicroSeismic determined the total SRV, the portion of the SRV that was propped, and, therefore, the portion that should be productive in the long term (Figures 2 and 3) for both

Figure 2: Wells A and B – Total SRV

Figure 3: Wells A and B – Productive SRV

wells A and B. MicroSeismic quantified the permeability enhancement of the reservoir using a 3D geocellular grid. The necessary scaling factors were obtained from Well A’s production and treatment data and used to translate the relative values of permeability enhancement to absolute permeability. The resulting absolute permeability multiplier was applied to Well B’s surface microseismic data to predict production and reservoir drainage patterns for both wells A and B. These simulations also provided a mechanism to determine optimal wellbore spacing.

Offshore World | 29 | October - November 2015

www.oswindia.com

FEATURES One key advantage of this workflow is the ability to capture the fracture intensity (fracture number, orientation, and aperture) achieved in each cell of the geocellular grid, which enables quantification of the permeability enhancement in each cell.

Client Uses Well spacing in this area of the Cleveland formation traditionally ranges from two to four wells per section or approximately 2,640 ft to 1,320 ft, respectively. Using microseismic data and reservoir drainage estimates provided by MicroSeismic, Peregrine implemented a down-spacing pilot project at 1,000-ft spacing and modified treatments to try to increase fracture half-lengths. The pilot wells are currently on flowback and are being monitored for results. Peregrine plans to continue testing different well spacing distances and fracture treatment designs to continue to maximise recovery of reserves.

Conclusion Currently, the industry does not trust theoretical reservoir models for detailed production prediction because everyone has learned how unreliable these models can be. The difference in deterministic-DFN reservoir models is that they are able to incorporate a reservoir’s state of permeability after hydraulic fracturing; therefore, they have the unique advantage of capturing details of the reservoir’s reaction to stimulation. This makes them fundamentally different from previous models. The added level of detail makes the models more deterministic and accurate.

As shown in this case study, MicroSeismic has already begun to prove the advantages of their deterministic reservoir models in understanding and forecasting production. MicroSeismic is currently using this technology with other operators in North America to help forecast production and reservoir drainage and optimise completions in unconventional reservoirs.

Figure 4: Actual production matches closely with MicroSeismic’s predicted production

Results When Peregrine compared Well B’s actual production to MicroSeismic’s predicted production, the prediction was shown to be a very accurate match (Figure 4).

This shows that the calibration tools MicroSeismic developed for Well B could also be used to reliably predict future production and reservoir drainage for other nearby monitored wells.

MicroSeismic recommended that Peregrine decrease spacing between wells to approximately 700 ft to ensure that valuable hydrocarbons are not left unproduced. MicroSeismic also identified excessive SRV overlap between stages, meaning that Peregrine could fracture fewer stages while still stimulating the same volume of rock. The microseismic analysis suggested that 16 stages would achieve the same SRV as the current 20-stage design. www.oswindia.com

Offshore World | 30 | October - November 2015

Sudhendu Kashikar Vice President - Completions Evaluation Microseismic Inc Email: skashikar@microseismic.com

Hasan Shojaei Research Reservoir Engineer MicroSeismic Inc Email: hshojaei@microseismic.com

Casey Lipp Geologist Peregrine Petroleum Email: clipp@peregrinepetroleum.com

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SEISMIC INDUCED MONITORING IN OIL AND GAS PRODUCTION: WHAT IS REALLY REQUIRED? Although many countries are pursuing fracking in a bid to replicate the success of the United States in developing the Bakken and other shale plays, there is heightened concern among regulators and the public these days about how unconventional oil and gas production operations – including fracking - could impact local seismic activity. The article highlights innovative technologies in seismic monitoring to help mitigate the impact of induced seismicity and new and future regulations.

T

here is heightened concern among regulators and the public these days about how unconventional oil and gas production operations – including fracking - could impact local seismic activity.

With fracking now a major source of international economic growth as companies discover the value of tapping large reserves of oil and gas from shale formations, many countries are pursuing fracking in a bid to replicate the success of the United States in developing the Bakken and other shale plays. China alone is reported to have nearly as much shale gas in reserve as the US and Canada combined.

Consequently, many nations will be looking at the early development of the industry in North America as particularly instructive on what they may wish to emulate or avoid in developing this industry. But in doing so, they must be aware of several negative aspects of fracking, including induced seismicity and regulatory restrictions that are being introduced in many jurisdictions to protect structures, people and the environment.

For tunately, innovative technologies in seismic monitoring have been developed to help mitigate the impact of induced seismicity and new and future regulations.

During the past 40 years, a dramatic evolution in the technology has meant that engineers, with state-of-the-art digital recorders, tri-axial down-hole sensor packages and real-time data rendering, can now monitor geo-mechanical phenomena at depths of greater than 10,000 feet. In the oil and gas sector, production and fracking operations can be monitored in near real-time so precisely that they can shut down immediately if a safety or operational situation arises.

Previously, seismologists often assumed each injection facility or region needed a network of observatory grade sensors capable of detecting and locating events to magnitudes less than 0, which is a very expensive proposition. The new systems have been developed specifically for induced seismicity monitoring, working within the relevant ranges of magnitudes pertinent for frac monitoring and regulatory compliance: 0.5 magnitude and larger.

A new generation of induced seismicity monitoring systems has recently been introduced that offers a low-cost alternative to traditional PMMs, plus various other benefits, which have created a paradigm shift for induced seismicity www.oswindia.com

monitoring. These are easy to deploy and efficient to operate and are designed for oil and gas operators who want to minimise the risk of mandated operational shutdowns, and regulatory penalties, resulting from the inducing of seismicity during fracking or fluid disposal.

Some are standalone systems designed, developed, and implemented by a highly trained earth scientists and engineers who have worked in the induced seismicity monitoring and regulatory sectors in the US, Canada, and overseas for more than 40 years. They aim to provide all stakeholders with greater peace of mind by ensuring that fracking operations are undertaken in a responsible manner in compliance with regulatory requirements.

Most O&G energy regulations rely on a ‘Traffic Light’ system which ties fluid injection activities (including fracking) to the location and magnitude of seismicity within a specified distance from a well. In North America, seismicity is usually monitored by state or province geological surveys in collaboration with national networks (e.g. United States Geological Survey or Natural Resources Canada).

In many areas, the government monitoring networks are sparse and epicentral errors can be as large as 10 kilometres. An area of 10 km can encompass many injection wells with different operators. Additionally, reported magnitudes from sparse networks can have significant random errors and can be biased high through a statistical phenomenon known as data censoring. The reported magnitude for an earthquake is the average of magnitudes from individual stations that detect the event and is usually based on peak amplitude measurements at each station which can show considerable scatter (random error). The positive magnitude bias occurs because of signal to noise (SNR)

Perhaps of more significance, these Next-Gen systems give operators the tools to remain compliant with all current and future regulations, while providing them with information to remediate their operations if necessary or required.

Offshore World | 32 | October - November 2015

FEATURES During the past 40 years, a dramatic evolution in the technology has meant that engineers, with state-of-the-art digital recorders, tri-axial down-hole sensor packages and real-time data rendering, can now monitor geo-mechanical phenomena at depths of greater than 10,000 feet.

considerations. Induced seismicity magnitudes of concern (i.e. felt) are typically of moderate magnitude (e.g. 1.5 to 5).

On a sparse network, where some stations are noisier than others, the signals will not always be of high SNR. Further, earthquakes radiate seismic energy preferentially in different direction (radiation pattern) depending on the type of faulting that occurs. Thus, the only sparse network stations reporting magnitudes from moderate sized events may be those on a favorable portion of the radiation pattern and that have quiet recording conditions.

Because of the considerations above, the consequences associated with a traffic light system can be severe to an operator and may be unfounded. If the operator has access to seismic data collected near the affected facility it is possible to avoid a costly shutdown and instead implement mitigation efforts, such as reducing well pressures and volumes for a short period of time.

What is needed for an operator to comply with regulations and to mount a defense against poorly reported seismic locations or magnitudes?

Most government (or university) seismic stations are observatory grade consisting of expensive data recorders broad band seismic sensors that are buried in the ground (in post holes or vaults). The systems are very expensive (upwards of USD 20,000), difficult to deploy and require significant power. The data from such systems is excellent and are capable of recording negative seismic magnitudes at local distances. However, traffic light regulatory systems typically call for no action on the part of an operator unless magnitudes are above local magnitude (ML) 2 within 3 to 5 km of a well. This means that seismic deployments necessary to meet regulatory requirements do not have to be overly expensive or complex. In many cases, a single station at a facility may be all that is necessary by providing event origin times, magnitude and distance (from S minus P arrival times). If seismic location is required then 3 or more stations are necessary. Event location has the benefit of visualising trends of seismicity and the possibility of locating fractures and faults.

Because background noise affects detection thresholds, a system such as QuakeMonitor developed by Weir-Jones and Associates and GeoEnergy Monitoring Systems, Inc, is designed to be placed on the surface typically at an injection facility (although seismometers can be buried as well). Noise levels at surface sensors are higher than those for buried sensors, but our deployments at injection facilities have shown that it is possible to detect ML = 1 to 1.5 events at a distance of 10 km and ML = 2 at 20 km. Although noise levels at a facility are higher than at some distance off site, there are advantages to placing units on site. First, finding sites and obtaining permits which can be time consuming and

costly is not necessary. Security is also not a problem for on-site deployments. In cold weather regions, such as the Boreal Plans in Alberta, marsh like conditions can occur with many bogs which can make travel to remote sites difficult as well as sensor emplacement. Engineered soil platforms available at injection facilities alleviate many of these problems.

For remote operations, narrow-bandwidth Orbcomm or Iridium satellite communication is used to transmit parameter data. One of the key components of the system for remote operation is the capability of on-board processing on an Atmel AVR 32 bit microprocessor on a Linux operating system. Sophisticated on-board processing algorithms allow parameter data including arrival time picks, signal polarisation, amplitudes and signal diagnostics to be transmitted via narrow bandwidth Orbcomm or Iridium satellite. This greatly reduces power consumption and allows the QuakeMonitor to be very small, lightweight and capable of remote operation for long periods of time (e.g. 6 months).

On board processing algorithms are physically based and have sound statistical underpinnings. This allows for signal processing parameters to be set prior to deployment in an area where little or no ground truth calibration data are available. For example, the commonly used Short Term Average to Long Term Average (STA/LTA) power detector has been modified for both detection and picking. Through construction of appropriate hypothesis tests, both detection and P-wave arrival time picking using the same STA/LTA values can be made using five preset signal processing parameters; short- and long-term window lengths, SNR detection level, effective bandwidth and false detection rate. Using signal processing parameters to set thresholds eliminates much of the uncertainty associated with placing an instrument in an uncalibrated region.

Perhaps of more significance, these Next-Gen systems give operators the tools to remain compliant with all current and future regulations, while providing them with information to remediate their operations if necessary or required.

Likewise, they can give regulators, interested third parties and the public greater piece of mind that frac operations can work within acceptable norms and regulatory requirements.

Dr Steven Taylor Principal Weir-Jones and Associates GeoEnergy Monitoring Systems, Inc

Offshore World | 33 | October - November 2015

www.oswindia.com

FEATURES

INDIGENOUS TECHNOLOGY FOR TATB: A THERMALLY STABLE, INSENSITIVE HIGH EXPLOSIVE HAVING VERSATILE APPLICATIONS 1,3,5-Triamino-2,4,6-trinitrobenzene (TATB) is an aromatic high explosive of special interest because of its insensitivity, thermal stability (>350°C), and respectable performance. The article explains the preparation of TATB and its application in defence and oil & gas sectors.

1,3,5-Triamino-2,4,6-trinitrobenzene (TATB) is an aromatic high explosive of special interest because of its insensitivity, thermal stability (>350°C), and respectable performance. The large-scale production of TATB is still an adaptation of Benziger route (Figure 1) from starting raw material 1,3,5-trichlorobenzene (TCB)[1].

Cl

NH2

Cl NO 2

O 2N

Nitration Cl

Cl

Oleum + HNO3

Cl

TCB

Cl

NO 2

O 2N

Amination Solvent,NH3

H2N

NH2

NO 2

NO 2

TCTNB

TATB

Figure 1: Benziger route for synthesis of TATB

TATB is a strategic material having applications in the warhead of long range missile, solid rocket propellant, and in Explosive Reactive Armour (ERA). Its import is restricted due to its application in critical defence system. HEMRL, a premier R&D laboratory under DRDO, has adopted Benziger route, and the process has been developed and established at a pilot plant [2]. TATB preparation by the Benziger method consists of two steps: TCB is first nitrated to 1,3,5-trichloro-2,4,6-trinitro benzene (TCTNB), and the product TATB is synthesised in the second step by amination of intermediate TCTNB in an organic solvent with ammonia gas. The results and lessons learned during indigenous development of TATB technology at pilot plant scale are summarised in this report. The application potentials of TATB are also discussed.

TATB Process The preparation of TATB consists of two-step processes: nitration and amination.

The different operations involved in TATB manufacture are summarised in the block diagram (Figure 2). A brief description of these two-unit processes is given below.

Nitration: TCB is nitrated in a batch process using a mixture of fuming nitric acid (98%) and oleum (20% SO3 content) as the nitrating agent. The reaction is carried out in a glass-lined steel reactor. It is a high temperature (>125°C) nitration process having

Figure 2: Process flow diagram for TATB www.oswindia.com

thermal hazards (runaway behaviour) close to operating temperature. Before scale-up, the thermal hazards were assessed using thermal screening unit (TSU), reaction calorimeter (RC) to define the safe operating parameters[3]. Automatic feeding system of three hazardous raw materials (TCB, nitric acid and oleum), temperature control system of the reaction mixture were developed indigenously and implemented in the pilot plant. The process yield is 90%.

Amination: Amination of TCTNB is an isothermal, single-feed, semi-batch, gas-liquid, heterogeneous, reaction crystallisation process. The chemical reaction and crystallisation occur simultaneously in this process. The product TATB and the bi-product NH 4Cl are formed at the gas-liquid interface. They are insoluble in the solvent selected for the present process, and hence, resulting in co-precipitation of crude TATB (TATB-NH 4Cl crystals). Crude TATB is further purified (removal of NH 4Cl by dissolution) by hot water digestion.

Unlike other military explosives (e.g. TNT, RDX, HMX etc), TATB is virtually insoluble in most common solvents. Thus, conventional crystallization is found to be unsuitable, and also uneconomical for further purification and for realizing TATB of different particle sizes. Hence, as a part of process development research, emphasis was given to the amination process for producing high purity TATB (low chloride impurity content) of reasonably large particle size (>50 μm). TATB of larger particle size gives a higher density, better fluidity, castability and solid loading in high explosive formulations. The chloride impurity in TATB causes compatibility problems in certain ammunitions, and hence, is detrimental to the storage life.

HEMRL has developed a wet-amination method to realise TATB of particle size (>50 μm) and low chloride content (~0.5%) [4,5]. An acid-recrystallization method has also been developed to realise chloride-free ultrafine TATB (UF-TATB) from production grade TATB [6].

Effluent Treatment HEMRL has developed the treatment methodologies for TATB process effluent.

The process generates three kinds of effluents: water-based nitration effluent (WNE), organic solvent based amination effluent (OSAE), and water-based amination effluent (WAE). Treatment methodologies for all these three effluent are developed[7]. WNE is neutralised by caustic soda and discharged it to effluent pit, where its natural evaporation resulted in the generation of solid waste, which is disposed of by land filling. Circulating WAE through an activated charcoal column was found effective to reduce the BOD and COD to an acceptable level. Solvent is recovered from OSAE, and the solid explosive waste generated from the residue of OSAE after solvent recovery may be used for preparation of moderately powerful explosive 1,3,5–triamino-2-chloro-4,6-dinitrobenzene (TACDNB).

Offshore World | 34 | October - November 2015

FEATURES Applications of TATB Application in Defence Sector: In a nuclear fission bomb, the high explosive shaped charges are arranged in a sphere which is called implosion device.

Simultaneous detonation of shape charges creates an explosive lens which exert very high pressure at the core where nuclear fissile materials e.g. plutonium, uranium are kept [Figure 3]. This high pressure increases the density of the fissile material resulting in triggering of nuclear chain reaction. TATB is used to make the explosive shape charges for nuclear fission bomb. Its high thermal stability and low impact sensitivity improves the overall safety of the nuclear weapon.

Figure 4 A: Perforating gun fitted with explosive shape charges; B: Penetration of zet in the rock during explosive gun shooting; C: Draining of oil and gas from well.

A new high temperature explosive, called HTX (High Temperature eXplosive) has been developed for perforating industry. HTX is a high explosive formulation made with TATB and HNS. The high thermal stability, impact insensitivity and VOD (Velocity Of Detonation) of TATB give the HTX formulation high-temperature rating with improved performance. The formulation has overcome the performance disadvantages that exist with HNS or PYX. HTX shaped charges are rated at 260°C for 1-hr and have been tested to 225°C for 200-hr continuous operation – long enough for most of the perforating operations. Thus, HTX is most suitable explosive for perforation of HPHT wells.

(Authors are thankful to Shri K P S Murthy, Out Standing scientist and Director, HEMRL for giving valuable suggestions to improve the text of this article, and also, for kind permission to publish this article in OSW.)

Figure 3: Explosive Shaped charges used in nuclear fission bomb

References

High burning rate Composite Propellant (CP) compositions (AP/HTPB/Al) are generally used in gas generators to eject missile from canister. Because of high burning rate, pressure index of the composition increases during burning which lead to over pressure inside the rocket resulting in rocket bursting/explosion.

Addition of TATB (up to 5%) in the standard CP composition is found to be very effective to reduce the pressure index, sensitivity and also improve the overall thermal stability of the CP[8].

Applications in Oil and Gas Industry: The hydrocarbon stock in the existing fields is getting depleted rapidly, and also, the easier targets are becoming scarce.

Thus, the searches of oil and gas are undertaken at deeper reservoir at high risk environment i.e. extreme pressure and high temperature [commonly known as highpressure and high-temperature (HPHT) well]. HPHT wells contain high-strength formation rock which is difficult to penetrate. The high pressure means that relatively more hydrocarbon is contained in these field compared with normal pressure field.

High explosive shaped charges are shot in wells with perforating guns in downhole conditions that range from benign to hostile –with temperatures approaching 250°C or more [Figure 4]. Downhole temperatures limit the choice of high explosive that can be used to manufacture shaped charges. The most commonly used oilwell perforating explosive is RDX, which is limited to temperature 170°C for a 1-hr exposure in a carrier gun. HMX (High Melting eXplosive, chemical name cyclotetramethylenetetranitramine) is used for temperature up to 200°C for 1-hr.

For more hostile wells, shaped charged with either HNS (Hexa-Nitro-Stiblene) or PYX [Chemical name 2, 6-bis (pycrylamine)-3, 5-dinitropyridine] explosives have been used. HNS has a 260°C, 1-hr temperature rating, and PYX has a slightly higher temperature rating. However, both HNS and PYX high-temperature explosives show poor penetration, and hence, their relative performance is lower compared to lower temperature explosives (RDX and HMX).

[1] Benziger T.M., Manufacture of TATB, 12th Int. Annu. Conf. ICT, Karlsruhe, Germany, 1981.

[2] Narasimhan V.L., Bhattacharyya S.C., Mandal A.K., Nandi A.K., Scaling Up the Process for Preparing 1,3,5-Triamino-2,4,6-trinitrobenzene (TATB), HEMRL’s Final Technical Report 6/2006, High Energy Materials Research Laboratory, Sutarwadi, Pune, India, 2006.

[3] Nandi A.K., Sutar V.B., Bhattacharyya S.C., Thermal Hazards Evaluation for sym- TCB Nitration Reaction Using Thermal Screening Unit (TSU), J. Therm. Anal. Calorim., 2004, 76, 895-901 [4] Nandi A.K., Kshirsagar A. S., Thanigaivelan U., Bhattacharyya S. C., Mandal A.K, Pandey R.K., Bhattacharyya B., Process Optimization for the Gas-Liquid Heterogeneous Reactive Crystallization Process Involved in the Preparation of the Insensitive High Explosive TATB, Cent. Eur. J. Energ. Mater.

2014, 11(1), 31-57.

[5] Nandi A.K., Kasar S.M., Thanigaivelan U., Mandal A.K., Pandey R.K., Formation of the Sensitive Impurity 1,3,5-Triamino-2-chloro-4,6-dinitrobenzene in Pilot Plant TATB Production, Org. Process.

Res. Dev., 2012, 16, 2036-2042.

[6] Nandi A.K., Kasar S.M., Thanigaivelan U., Ghosh M., Mandal A.K., Bhattacharyya S.C., Synthesis and Characterization of Ultrafine TATB, J. Energ. Mater., 2007, 56, 213-231.

[7] Nandi A.K., Sutar V.B., Jadhav V.V., Mali N.P., Mandal A.K, Pandey R.K., Bhattacharyya B., Hazardous Wastes Generated in Manufacture of High Explosive 1,3,5-Triamino-2,4,6-trinitrobenzene(TATB), J. Hazard. Toxic Radioact. Waste, 2014, 18, 04014014.

[8] Mehilal, Shekhar Jawalkar, Ramesh Kurva, Nandagopal Sundaramoorthy, Ganesh Dombe, Praveen Prakash Singh and Bikash Bhattacharya, Studies on High Burning Rate Composite Propellant Formulations using TATB as Pressure Index Suppressant, Cent. Eur. J. Energ. Mater., 2012, 9(3), 237-249.

Amiya Kumar Nandi Scientist E High Energy Materials Research Laboratory (HEMRL) Email: nandi.ak@hemrl.drdo.in Dr Raj Kishore Pandey Scientist ‘G’, Associate Director High Energy Materials Research Laboratory (HEMRL) Email: rkpandey@hemrl.drdo.in

Offshore World | 35 | October - November 2015

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FEATURES

TEMPERATURE MEASUREMENT IN THE MODIFIED CLAUS SULFUR REACTOR TO MEASURE TEMPERATURE OR NOT? Measure temperature or not in the Claus Sulfur Reactor (furnace) has been a constant debate among operators while it is a typical gas plant where the concentration of H 2S is known and is constant because there is no control over it. But in a refinery or gas plant that receives its feed gas from a variety of different sources, the operator needs to constantly monitor the composition of the feed gas, adjust the mixture ratios accordingly and watch for refractory damaging temperature excursions resulting from unexpected feed loads. The article explains various methods to measure temperature in the Claus Furnace at refinery or gas plant.

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here are two schools of thought on temperature measurement in the Claus Reactor (furnace). One is typical of the gas plant where the concentration of H 2S is known and is constant. Why measure the temperature when there is no control over it? Constant flow with sufficient air to burn one-third of the H 2S will produce a constant reproducible temperature, and so long as the mixture ratio remains constant, there is no need to know the temperature.

The other school of thought is in the refinery or gas plant that receives its feed gas from a variety of different sources. The operator has to constantly monitor the composition of the feed gas, adjust the mixture ratios accordingly and watch for refractory damaging temperature excursions resulting from unexpected feed loads. The implementation of O 2 enrichment increased operating temperatures making reliable temperature measurements a critical requirement.

There are two critical temperatures required for the safe and efficient operation of a Sulfur Furnace: 1) Refractory temperature is critical for furnace high temperature alarms and automated shutdown systems. This temperature represents the infrastructure temperature and the high temperature limits are specified by the engineering design. However using only a refractory measurements for furnace control offers no early warning of a high temperature excursions.

2) Combustion temperatures offer the operators process temperature information and early warning of temperature excursions before they are absorbed by the refractory and create a refractory temperature excursion that eventually trigger a high temperature alarm or shut downs. The ability of combustion temperature measurements to provide an early warning of a critical temperature event makes it a necessary for higher operating temperature in an O 2 enriched environment.

Temperature measurement in Claus Plants is the norm and non-temperature monitoring is very rare.

How to Measure Temperature in the Claus Furnace The ‘EYEBALL’ Method: The most common is the ‘EYEBALL’ method. The experienced operator simply looks into a viewport and observes the color of the

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PULSAR 4 Installed in Claus Reactor

Refractory temperature is critical for furnace high temperature alarms and automated shutdown systems. This temperature represents the infrastructure temperature and the high temperature limits are specified by the engineering design.

Offshore World | 36 | October - November 2015

FEATURES Combustion temperatures offer the operators process temperature information and early warning of temperature excursions before they are absorbed by the refractory and create a refractory temperature excursion that eventually trigger a high temperature alarm or shut downs.

combustion process. Surprisingly, some operators can estimate the temperatures within ± 50°C. LumaSense publishes a color/temperature pocket card which allows the novice to estimate the temperature within 100 to 200°C. Some will scoff at the ‘EYEBALL’ method, but it has saved many a reactor from potential destruction under the watchful eye of an alert operator.

Thermocouples (T/C): The most widely used instrument in the Claus Furnace is the thermocouple. In most installations, T/C’s (and other resistance temperature devices, RTD’s) do not stand up under the rigors of the Claus harsh environment.

Highly corrosive H2S at 1315°C (2400°F) combined with combustion vibration and thermal shock are just too much for most T/C installations. Fast response, thin wall ceramic Thermowell (metal won’t hold up at these temperatures) prove too brittle to endure thermal shock and combustion vibration. Very thick Thermowell react too slowly and only offer refractory measurements.

One area where T/C’s are successful is when they are imbedded just below the refractory surface. This type of installation is useful for refractory protection.

Infrared Thermometer (IR-T): The IR-T can be mounted outside the environment of the combustion process sighting through a viewport into the Claus Furnace.

IR-T solutions offer wide temperature spans, fast response times, and selectable wavelengths to view the combustion process temperature and refractory temperatures. Typical industrial pyrometers measure single temperatures and are subject to flame transparency changes in the furnace as feed changes occur.

will add components of the flame temperature to the refractory measurement creating a higher IR refractory measurement than actually occuring. The issue is also enhanced by the changing flame transparency as feed stocks change over time creating a variable error in a typical single wavelength pyrometer.

Note: By two wavelength pyrometer we are not referring to the industries typical two colour pyrometers that use comparative wavelengths to compensate for dust and other attenuating applications. The two wavelengths we are referencing here are seperate refractory and gas (flame/combustion) detectors and filters.

By the use of both a refractory measurement and gas (flame/combustion) measurement and applying a flame transparency compensation algorithm, the varying flame transparency can be removed and corrected in the individual refractory and gas measurement outputs of the pyrometer.

LumaSense has combined the two wavelengths for refractor y and gas measurements into a single pyrometer that limits the installation and maintenance cost. Combine this pyrometer with our proprietary Flame Measurement Algorithm (FMA) to create the PULSAR 4 next generation SRU and Sulfur Burner Infrared Temperature Measurement Pyrometer system.

Using a pyrometer with two separate detectors with separate filters that specific to refractory and gas (combustion) measurements with s anolog and digital signal outputs is prefered over individual installations of single wavelength pyrometers requiring two separate pyrometer installations at a higher installation and maintenance cost. The second benefit of having two seperate detectors filtered for refractory and gas measurements is the capability to apply flame transparency algorithms to the output to reduce flame impingement on refractory measurements and flame transparence in the combustion (gas) measurements.

Typical industrial pyrometers face challenges when measuring flame (gas) or thru Flames (gas). When clean burning, the flame can become partially transparent to the gas wavelength being used. This transparency will allow some refractory to be seen and the refractory temperature to be included into the pyrometer measurement resulting in a lower measurement for the gas temperature than is actually occuring. In the case of a dirty or larger flame, the refractory wavelength measurement will have elements of the flame temperature due to low flame transparency. In this case, the lack of transparency of the flame Offshore World | 37 | October - November 2015

David Ducharme E2T Product Manager LumaSense Technologies E-mail: d.ducharme@lumasenseinc.com www.oswindia.com

FEATURES

OIL AND GAS FIELDS GET SMART While the current oil & gas sector has been shifted from traditional work process to more integrated and holistic operations, Automation & IT has led a rapid paradigm shift to the activities & operations in the oil & gas sector by advent of newer & smarter informational and operational technologies. The article highlights some of the technologies which have already impacted the sector in detail.

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he oil and gas sector has seen a shift in recent years from silos to more integrated and holistic operations. With the advent of smart wells and real-time automation technologies, companies are looking at their assets and operations in a new light. Developments in informational and operational technologies have been groundbreaking in the past decade with technologies such as Distributed Thermal Sensing (DTS), Zonal Flow Control (ZFC) and Downhole Gauges (DHG) becoming more prevalent in oil and gas organisations.

With the availability of real-time data and insights into daily operations, the improvement of innovative ideas from present smart field initiatives will pave the way for new technological advances and the oil and gas fields of the future.

functional understanding, enhancing individual performance and boosting overall company productivity.

Some technologies already impacting the sector include:

Closed-loop Reservoir Optimisation With the gradual adoption of smart well advancements, production in some operations is still carried out independently. The value of technologies such as DTS, ZFC and DHGs, will increase exponentially when used as part of a closedloop control with surface automation technology. With a number of scenarios possible, an out-of-the-box approach is required when merging and optimising production and automation technologies. The adoption and convergence of realtime data-driven models in conjunction with some of the above technologies is set to vastly improve and radicalise operations throughout the sector. The integration of the IoT alone, will shape the future of the oil and gas industry not only optimising the way production is carried out, but radically changing the way oilfields are operated.

Internet of Things (IoT) The IoT is currently a buzz word among technology enthusiasts and is an exciting prospect, allowing machines to provide detailed diagnostics and data while sharing information about processes in real-time. Preventative maintenance reporting can be embedded directly at the source, allowing for immediate corrective responses and minimal production losses. This will be particularly advantageous where resources are scarce and assets are located in remote facilities.

Robotics Remotely operated vehicles (ROVs) have long been used in offshore production facilities. However, with exploration increasingly carried out in inaccessible areas, using robots for routine maintenance and inspection activities is becoming more attractive. Drones are also utilised as surveillance tools, on a small scale by some oil and gas companies. Equipped with an infra-red camera, a drone soon becomes a real-time, mobile leak-detection device. It will be interesting to see how these technologies will integrate into operational activities once applied on a larger scale, and within the oil and gas industry overall.

Multi-disciplinary Workforce The trend towards oil and gas organisations adopting a multi-disciplinary approach is on the increase. Automation and IT disciplines now better understand exploration and production dynamics, thus becoming more conversant in identifying gaps in production. A multi-disciplinary approach will have a positive impact on how companies collaborate in the future, facilitating improved cross-

Improved Real-time Fluid and Petro-physical Analytics Ironically as an oil and gas company’s main asset and revenue source, reservoirs tend to be one of the most unfamiliar places. In smart oil and gas fields of the future, properties like viscosities, pressure volume-temperature, chemical reactions and diverse rock types; could be monitored in real-time. Thus vastly improving operational effectiveness, with more informed and timely decision making.

Enhancing Your Performance Through increased energy-related operational efficiencies, you can offset your upfront investments with the money you save over the long term. Further, by improving the quality and continuity of your electricity production and performance, your operations can reach their full potential, while ensuring your safety and regulatory compliance.

At Schneider Electric, we see an innovative world where collaborative solutions can help you maximise your energy, while using less of our common planet. As your trusted partner, we deliver custom engineered solutions that employ proven technology, ensure optimised levels of availability and efficiency and protect your processes and operations at every step.

Growing global energy demands and environmental and safety regulations are making energy-efficient Oil & Gas operations even more critical to the world’s energy mix. www.oswindia.com

Offshore World | 38 | October - November 2015

Dr Peter Martin Vice President - Business Value Solutions Schneider Electric

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FEATURES

IDENTIFYING TECHNOLOGIES TO REDUCE DRILLING BUDGETS IN THE LOW OIL PRICE ENVIRONMENT In the backdrop of current plunging oil price, rig counts remains half of what it was at the start of the year, thus operators need to streamline & restructure operations – especially drilling operations which is considered lion’s share of rig days.

Reducing the days required in reaching a target zone is the easiest way to reduce overall project cost and reducing risk of failure and increasing efficiency is another aspect of a drilling programme. The article explains advance technologies to increase directional drilling accuracy by facilitating new methods of data transmission and building upon existing reservoir characterisation methods.

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urrent oil prices remain low and the rig count remains half of what it was at the start of the year. These conditions are causing operators to restructure and streamline operations. With rig day rates being the lion’s share of drilling operations, reducing the days required to reach a target zone is the easiest way to reduce overall project cost. Ultimately, this means reducing risk of failure and increasing efficiency for any aspect of a drilling programme. New technologies are solving these issues in several ways: increasing directional drilling accuracy, mitigating equipment failure, and ensuring wellbore stability.

To increase directional drilling accuracy, operators seek to better understand geology and improve downhole data transmission and analysis. Companies like Waveseis, which provides advanced seismic imaging for subsalt structures, can improve reservoir understanding and mitigate drilling hazards by providing more accurate subsurface imagery. Waveseis accomplishes this by using a proprietary algorithm that improves upon existing Reverse Time Migration (RMT) techniques.

The oil and gas industry is also seeking ways to improve data transmission from directional tools. Improving data transmission has proved to be a difficult task to the oil and gas industry, which still relies broadly on mud-pulse systems.

XACT Downhole Telemetry and Evolution Engineering seek to provide alternative systems to traditional mud pulse. XACT‘s system uses acoustic signals sent through the drill pipe to transmit data from the borehole to the surface.

Measurements are taken at the bottom of the drill string and transmitted to the surface through a network of distributed nodes. The system can operate independent of fluid flow unlike mud pulse systems. Just last January, XACT completed its first deepwater deployment in the Gulf of Mexico with BP. Evolution Engineering seeks to improve on existing technology by combining mud pulse telemetry and electromagnetic telemetry in one MWD tool. The tool has been designed to withstand high volumes of lost circulation material.

While there are complex solutions for mitigating equipment failure, such as data analytics for preventative maintenance, there are also options that reduce risk directly at the wellhead. 5D Oilfield Magnetics has developed a system that captures tools and metal shavings in a magnetic chamber above the wellbore.

The system is viewed positively by Lux Research Analysts for delivering an actionable solution to an often ignored wellsite problem. 5D Oilfield Magnetics’ Open Hole Net sits above the annular preventer and can be easily accessed by workers to remove tools or metal shavings. The company has also developed

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a tool specifically for managed pressure drilling. Tools accidentally dropped downhole can wreak havoc on expensive directional drilling tools, resulting in both down-time and expensive replacements. While there are no statistics on how many non-productive time cases are caused by dropped tools, mitigating one dropped tool incident could save operators hundreds of thousands of dollars.

Approaches to improving wellbore stability range from improved pore pressure predictions and real-time pressure monitoring services, provided by companies like Ikon Sciences, to dual drill string technology developed by Reelwell. In addition to these technologies, development of innovative lost-circulation materials has also been a topic of interest. Recent advancements include cross-shaped proppants developed by advanced materials company Hoowaki and nanocellulose crystalline

by CelluForce. Hoowaki’s X-shaped proppant, which won Statoil ASA and GE Oil & Gas’ Innovation Challenge, is designed to tumble or flutter like a leaf, opposed to sinking straight down like traditional spherical proppant. While these materials have yet to be produced and deployed at commercial scale, early interest suggests “designer” materials could be more popular in the future.

Conclusion With prices likely to remain depressed and drilling activity reduced through 2016, start-ups in the oil and gas industry will be under more pressure to deliver innovations that reduce overall cost. While the barrier to entry is high, opportunity still exists for start-ups during the low oil price market. In the long-term, the industry will continue to advance drilling accuracy by facilitating new methods of data transmission and building upon existing reservoir characterisation methods. More near-term improvements could include market adoption of tools that act as added insurance against incidents that result in lost drilling time and expensive repairs. Overall, technologies with high-appeal will reduce cost by increasing drilling accuracy, mitigating equipment failure and improving wellbore stability.

Contact: carole.jacques@luxresearchinc.com

Offshore World | 40 | October - November 2015

Colleen Kennedy Research Analyst Lux Research

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Virtualisation – Software Defines Revolution for Plants Plant operations comprise of multiple applications and functions with the help of separate and various servers to measure real-time integration and plant performance. Each server becomes an additional burden to plant operations due to the maintenance and space required. After decades of executing automation projects in the traditional way, it is time for new thinking because in today’s demanding economy, industrial companies must deal with the overarching task of doing more with less, which means reducing operating costs while maintaining or increasing production levels. Here is where virtualisation comes into play - a technology that allows multiple operating systems to share a single server machine. The article details on new virtualisation technologies in reducing the amount of computer hardware in plant and the Total Cost of Ownership (TCO) of plant operators, without compromising the existing safety, reliability and production of the plant or industry.

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maintaining or increasing production levels. Inefficiencies can prove costly and can impact planning, return on invested capital and cash flow. Tweaking the project execution process can result in incremental improvement, but does not really move the needle.

Because of these issues, reducing the number of physical machine required for plant operations has become a priority – with each server being removed, maintenance and operational costs decrease. But they can’t be removed at the expense of overall plant reliability.

After decades of executing automation projects in the traditional way, it is time for new thinking. Why is it necessary to order physical systems at the beginning of the project? Why must groups of people travel across the globe to remote locations? Why force hardware freezes prematurely? And why should design be coupled to hardware? Now, more than ever, paradigm shift in project execution methodologies is needed to increase capital efficiency and enhance predictability in cost and schedule on automation projects.

n today’s world, plant operators are burdened with maintaining separate servers to support multiple applications and perform various functions within their plants. Each server becomes an additional burden to plant operations due to the maintenance and space required, as well as in the amount of power and cooling system requirement. Further, facilities also deal with constant hardware and Operating System (OS) upgrades, complications in system management, operational pressures to reduce overall Total Cost of Ownership (TCO).

Here is where virtualisation comes into play - a technology that allows multiple operating systems to share a single server machine. In simple term, virtualisation is taking one of these physical servers and splitting it up into many virtual servers.

The process of virtualisation works by inserting a thin layer of software called the hypervisor directly on the computer hardware. The hypervisor layer presents multiple sets of ‘virtual hardware’ which contain the same components as a regular machine (e.g., motherboard, chipset, etc). To an operating system, virtual hardware is indistinguishable from a regular machine.

Transformation of Workflow Changes in project implementation strategies support the traditional (i.e. define, design, manufacture and install) workflow for the physical hardware components and an independent workflow (i.e., define, configure, test) for the functional software. In the case of functional development, there is no penalty for breaking the workflow into modular functional packages. For example, a utilities process unit could be functionally completed prior to starting another production unit that may have a less complete definition. This enables the project team to be more agile in supporting the fragmented data inputs that result from parallel upstream design activities.

The virtual hardware, along with the virtual disk, operating system and application, can all be encapsulated in a single set of files which is called the ‘virtual machine’. In allowing multiple virtual machines to run on a single set of hardware, the hypervisor enables that they remain totally isolated from one another and from the underlying physical hardware. This prevents an issue on one virtual machine from propagating to another and also allows a virtual machine to move from one physical machine to another as it’s not coupled to the underlying hardware.

In the evolution of process automation, the functionality of control systems has moved steadily away from dependency on hardware to software configuration.

The functionality can be applied to multi-purpose hardware supporting a greater variety of functionality with fewer, more versatile standardised components. In this sense, the software configuration supports control system functionality while the hardware supports physical requirements, such as Input and Output (I/O) connections that are universal and can be changed remotely.

Today’s Challenges In a demanding economy, industrial companies must deal with the overarching task of doing more with less, which means reducing operating costs while

Advent of New Technology Thanks to technologies such as Universal Input/output (UIO), Virtualisation and Cloud Engineering (Virtual Engineering Platform), industrial firms can

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Offshore World | 42 | October - November 2015

FEATURES Virtualisation is a powerful tool for improving the reliability and cutting the cost of maintenance and inventory in the process plant.

The true value of the return of investment would be realised at both ends of a particular projects schedule and will prove to be a true paradigm shift. now transform the way in which plant automation projects are executed.

These technologies are specifically designed to decouple physical design from functional design. They support key project benefits such as: late binding of system configuration data, flexible hardware procurement, improved agility and flexibility, and enhanced design options. Solutions such as – Lean Execution of Automation Projects (LEAP) - can have a significant impact on large capital mega project implementation, talking millions of dollars off the total installed cost of large control system projects.

With the virtualisation technology, it is now possible to achieve full abstraction of the control system infrastructure. Supervisory Control Level 2 nodes are abstracted via virtualisation, while Control Level 1 and I/O can be fully simulated in a server environment and abstracted by the Universal I/O. This overall abstraction from the server to the I/O fosters the LEAP approach, which brings greater versatility to the traditional model of an engineered automation system.

Universal I/O In the process of physical design for control systems, the objective is to start the design task as late as possible. Removing configuration activities from the critical path is one step towards that goal. Next step is to reduce the time taken for design by simplification of the design process itself. The development of Universal Channel Technology has liberated field I/O as well as control cabinets from channel-type dependency. This more standardised, multifunctional solution permits late additions and modifications to I/O schedules with no more than a soft configuration change potentially saving weeks of schedule delay when making late-stage design changes.

Through the use of Universal I/O, late data binding situation can occur well into the construction phase of a project without the huge impact that late instrumentation design changes (i.e. a disabled situation which occurs at a later stage of any process) would typically bring to conventional designs. Users no longer require different modules for each I/O type, and are able to reconfigure any I/O channel without having to go into the field to make physical changes. And since Universal Channel Technology has ushered in a more standardised design approach based on the use of a single Universal I/O module, standard cabinet designs can be manufactured later in the project schedule.

Another major advantage with the Universal I/O solution is, project teams can start work sooner — the operator just requires a total I/O count and does not need to worry about the I/O mix. Universal I/O modules reduce equipment requirements and footprint processes and can be quickly configured for multiple channel types enabling flexibility in system design. This concept enables multiple remote locations to be controlled out of a single centralised unit with each

channel of I/O individually software-configured either as Analog Input (AI), Analog Output (AO), Digital Input (DI) or Digital Output (DO).

Hence Universal Channel Technology’s enhanced design options makes it possible to utilise remote cabinet designs with corresponding savings in equipment space, power, cooling and weight requirements. It eliminates wasted I/O space and enables reductions in both installation and operational costs since users are no longer concerned about having sufficient modules for I/O configuration. The I/O connection can easily be configured and reconfigured at any point.

Virtualisation Plant managers seek to reduce the amount of computer hardware in their facilities and their Total Cost of Ownership (TCO), but they must do it without compromising existing safety, reliability and production. Simply put, virtualisation abstracts operating systems and applications from the underlying physical infrastructure by representing the hardware as virtual devices. Virtualisation allows a single server to simultaneously run multiple operating systems and applications. It does this while insulating these Virtual Machines (VMs) from the underlying hardware and also from each other. Virtualisation is now proving to be an important productivity and efficiency tool for all types of industrial operations. Targeted virtualisation solutions simplify and decrease requirements for plant hardware while enabling greater reliability and availability of process control systems.

Virtualisation makes a significant contribution to design independence on automation projects. Traditional methods of deploying process control systems have involved a tight coupling between control functions and the instruments connected to the process. When projects are provisioned with virtual machines rather than physical servers, virtual infrastructure purchases can be deferred until later in the project. The actual hardware is not procured until after final testing so that users can buy the most current technology thereby avoiding a costly hardware refresh during project execution. It allows for a single, standardised workstation and server design that can accommodate a wide variety of topologies in a similar manner to Universal Cabinet designs.

Plants also achieve greater agility and flexibility with Virtualisation technology.

Virtualisation allows project engineers to add new virtual machines without requiring new hardware (within limits). This helps plant operator start their work sooner without worrying about a precise VM count (virtual machines). And if additional nodes are required, they can be handled on the existing hardware assuming sufficient capacity. And by using virtualised templates, new nodes can be spun up effortlessly without having to do complete installs.

Additionally, virtualised servers with a thin client operator interface are the best option for many applications commonly found in the plant control room. Like

Offshore World | 43 | October - November 2015

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FEATURES Cloud engineering can deliver the functionality required by industrial firms that want to transform the way in which they operate to achieve a competitive advantage.

the server room, footprint processes can be optimised in terms of equipment space, cooling and noise. Additionally, thin clients have the flexibility to be geographically separated from the facility, using reliable redundant network connectivity.

Cloud Engineering Today, more and more engineering and industrial companies manage their projects across multiple locations. Project teams are no longer defined by geographical proximity anymore. Instead, engineering professionals work as a - human cloud that is made possible; thanks to the rapid development of new cloud computing technologies. For companies that have global development and manufacturing operations, the ability to share data without being limited by time or place helps their various locations collaborate more closely. It also allows engineers to concentrate on their work rather than how, when, and where their jobs are executed. Cloud engineering solutions enable automation work around the world to be engineered in the cloud in a manner that is decoupled from the physical infrastructure. The VMs or databases can then be bound late in the project cycle with the physical hardware.

Cloud engineering solutions enable automation work around the world to be engineered in the cloud and decoupled from the physical infrastructure.

The VMs or databases can then be bound late in the project cycle with the physical hardware.

One of the basic advantages of the cloud engineering approach is the freedom to use the automation supplier’s infrastructure during the project engineering process. This allows the project to procure the project servers as late as possible in the schedule. This way the technology is delivered with the system that uses the latest hardware available.

advantage. Companies are running applications in the cloud to lower costs, deploy more quickly, and simplify infrastructure management. The ability to detect and react quickly to issues reduces waste and elapsed time, which reduces costs and improves time to market. The combination of virtual engineering with full virtual target system deployment yields the highest possible benefits in terms of engineering design efficiency, quick deployment, late change management, flexible hardware procurement, and footprint for automation projects.

How is the Optimised Technology Beneficial?

When applying optimised project workflows in a particular project, a number of tasks that previously occurred in a system-staging environment can now be pushed out to the construction phase to enable earlier on-site delivery of hardware. With Universal I/O, users can now order standard Universal Cabinets from the factory in whatever quantities required and execute a project without assigning I/O to a channel until commissioning. With virtualisation and product simulators, control strategies can be developed and tested prior to the final design, and users can develop those strategies in the cloud and allow the project engineer never to leave home. Applied together, these technologies enable a new project execution methodology that revolutionises project execution.

Conclusion Virtualisation is a powerful tool for improving the reliability and cutting the cost of maintenance and inventory in the process plant. The true value of the return of investment would be realised at both ends of a particular projects schedule and will prove to be a true paradigm shift. Another powerful, yet lesser-known benefit of virtualisation is the business continuity and disaster recovery. By making process systems in plants less likely to fail and by making server restoration sustainability faster, virtualisation enables plants of all sizes reduce the cost of downtime. For process plants virtualisation acts as an important insurance policy.

With a virtual engineering platform, Subject Matter Experts (SMEs) have fewer physical constraints and can start work on the project without waiting for servers or other components. As all of the control functions have been virtualised, remote testing is possible. This can be done through allowing more iterative remote inspection during the detail design phase of a project, reducing the need to test these areas during a Factory Acceptance Test (FAT) or, alternatively, a traditional FAT could be conducted where large portions are performed remotely. Either way, large reductions in travel expenses are achieved on order of 50-70 per cent for testing. Once the virtual FAT has been completed, the virtual machines are moved from virtual staging resources to the final servers for the site acceptance test (SAT). As the machines have been virtualised, nothing needs to be reloaded or reinstalled when they are transitioned to the final hardware.

Cloud engineering can deliver the functionality required by industrial firms that want to transform the way in which they operate to achieve a competitive www.oswindia.com

Offshore World | 44 | October - November 2015

Sanjay Sharma Engineering Head, PAS Honeywell Process Solutions, India Email: Sanjay.k.Sharma@honeywell.com

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SMART REFINERY: ENHANCE THE PRODUCTIVITY OF PLANT IN MANIFOLD While advance in sensors, wireless, predictive technologies and automation have significantly changed the way refineries operate today, the complexity in refinery operations continues to increase with refiners adding units to provide flexibility in processing opportunity crudes, and relying on crude blending to give the right feedstock properties to best utilise the refinery design coupled with complying with new and existing government regulations. The article explains on smart refinery solutions that could enhance improvements to energy efficiency, safety, health and environmental issues, value addition, cost control, mass and energy balance and overall energy conservation of a refinery.

W

hen managing a complex and dynamic operation like an oil refinery, having the predictability to minimise unplanned shutdowns and slowdowns is critical to safe, reliable and profitable operations. Having the visibility and insight to ‘be alerted and take timely corrective action’ is the characteristic of a world-class operation. It means being more informed and smarter about each decision made and action taken. In reality, ‘smart’ technologies have been around the refining industry for a couple of decades.

In fact, process automation, control and monitoring technologies get smarter every year. But are they actually improving refinery business? Are they helping address the impending skilled workforce crisis all industries are facing? Are they helping provide flexibility to change production strategies to profit from opportunity crude oils? Are they giving confidence to operate the refinery at rated capacities while ensuring safe operating conditions? Access to subject matter experts whether onsite or remotely? Technology enables your staff the ability to operate reliably, safely, and profitably. What is referred to as the ‘Smart Refinery’.

The complexity in refinery operations continues to increase with refiners adding units to provide flexibility in processing opportunity crudes, and relying on crude blending to give the right feedstock properties to best utilise the refinery design. Product specifications have simultaneously become more geographically complicated and restrictive. Regional and local fuel specifications including the use of biofuels often lead to multiple product blending steps and transport restrictions. In addition, refiners require special processing for their unique needs in asphalts and lubricating oils. Complying with new and existing government regulations is demanding on resources. Now, more than ever, efficiency and consistent productivity are required to stay viable in a commodity based market with far-reaching boundaries for competitors. Advances in automation are enabling refiners to achieve these efficiencies and improve the overall performance of their plants - decreasing costs and increasing profits. The cost and size of computing elements, the continuing increase in communication bandwidths, advances in software and mathematical analyses and better modeling capabilities have provided new optimising tools for increasingly reliable refining operations. This is not just a vision of the future; it is today’s reality for top quartile performers. Many new developments such as improved process sensors and measurement devices are being applied. The era of the ‘smart refinery’ is today.

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How is the smart refinery different? In a very important way, it isn’t. The operating objectives for the refinery still include: • Maintaining safe operations • Enhancing environmental stewardship • Sustaining high equipment availability and reliability • Maximising plant and product value through efficient and optimised operation • Ensuring refinery staff maintain required skills and stay current with changing technology Advances in automation technology including the implementation of pervasive sensing to bring process and asset condition data to both operations and maintenance enable new and better ways to integrate work processes and improve the timeliness and accuracy of decisions. Significant improvements in plant performance are possible when the right expertise is applied at the right time; when personnel have the information they need to make quality decisions quickly, and when they have access to specialised supplemental expertise when they need it. Most processing facilities are balancing the needs for safety, quality, profit, environmental compliance, and reliability against the challenge of applying the right knowledge across organisational and geographic boundaries while simultaneously reducing costs. Therefore, many companies are taking advantage of technologies such as virtualisation, remote monitoring, enhanced KPIs and dashboards, co-location of personnel, control room consolidation, etc.

For example, a US West Coast refiner implemented wireless vibration sensors on essential pumps to monitor asset health (to improve production availability) where a wired solution was not cost effective. Similarly, a US Gulf Coast refiner showed sustained 50 per cent reduction in reliability risk (increased availability) by incorporating a smart refinery technology enabling refining staff the ability to effectively use additional information. It should be stated that technology alone is not the solution – staff need to be trained on how to use the new information.

The new smart refinery will complement the console operator, control engineer and maintenance technician, improving their efficiency and decision-making with timely, actionable information. With any new technology, ease of use and ease of integration with existing operations are key factors. For example, Emerson Process Management carefully considers the effects of smart refinery technologies, not

Offshore World | 46 | October - November 2015

FEATURES Cloud engineering can deliver the functionality required by industrial firms that want to transform the way in which they operate to achieve a competitive advantage.

only on present staff, but also on successfully transferring critical knowledge to younger operators as a significant number of older, experienced operators retire.

The continuing evolution in digital computing and communication capabilities – and the application of these technologies – has led to fundamental differences in the way refineries operate and will continue to change the way they operate in the future. However, staff needs to be trained to use the technology effectively to capture the benefits of new information. Improvements in information and processes in place to utilise the information can be worth millions of dollars a year, and competitive cost advantage.

In today’s economic environment, management demands that new investments provide low risk and expected rate of return on both new and existing assets, particularly automation assets. Investments in smart refinery technology often provide some of the highest economic paybacks of any possible investments, and these expected returns can be determined in advance and demonstrated after implementation. Both new and existing plants can get quick return on investment and sustainable value by investing in smart refinery technology. New plants can easily take advantage of state-of-the-art technology and processes right from initial startup, but existing plants can also benefit. Existing refiners can start small and gain experience by implementing upgrade programmes at a measured pace that can be self-funding with benefits from early installations paying for the later stages. Smart refinery operators now have the opportunity to leverage these investments to enhance the safety, reliability, productivity and profitability.

Increasing regulatory requirements, refinery complexity and demands for higher quality continue to place higher economic demands on refineries while reducing operational margins. The new smart refinery can offset these barriers. Technology enables and enhances this smart refinery. For example, wireless technology extends sensor reach, enabling smart refinery operators to monitor areas of the plant that were previously inaccessible due to location or significant wiring installation costs. Because of automation, the smart refinery has the ability to predict maintenance issues, alert and take timely action to prevent failures and greatly improve plant and process reliability. Not only does this translate into more efficient operation, higher product quality and reduced maintenance costs, it also means that the smart refinery has improved and increased uptime, which adds dollars to both the top and bottom lines.

Smart refining offers more than just leveraging state-of-the-art technology.

Evolving developments are leading to new methods and procedures for plant operation; increased monitoring capabilities that continually check the pulse of the refinery; advanced modeling and analytics that compare refinery production against expectations; earlier detection of abnormal conditions or imminent failure; and tools that can plan future operation with increased confidence. These technology developments enable significant changes in the way refineries operate.

Most refineries were originally constructed with the minimal amount of instrumentation required to operate the plant. What we see in the future is more use of collaborative software tools, and standards-based software and hardware to reduce ongoing support costs. The operating systems of the future will process, store and analyse much more data and information, including many more sensors in primary and secondary locations and a wider range of live video and spectral data. This data will be analysed and displayed as information to be acted on in a timely manner.

The technologies that are being put into the marketplace today are only the stepping stones to that future. Another smart refinery trend is toward increasing levels of remote operation. Individual refineries can be geographically dispersed.

Control rooms can be many miles from the physical units. Complete information on the state of the plant can be communicated to the remote control room. Fully reliable automated plant startup and shutdown systems enable safe remote operations. Today, major sites operate across hundreds of miles. In the future, smart refineries will continue this trend, placing greater demands on reliable automation and communication.

Fortunately, the automation developments that support these remote operations have kept pace. While smart sensors, wireless, predictive technologies and automation continue to make the smart refinery even smarter, these enablers do not replace the power of the human decision-making process, nor the accompanying responsibilities. Technology must be used, not only to make the smart refinery more productive and more profitable, but to make it safer as well.

Smart refinery operators have the opportunity to deploy these technologies to ensure the safety of their personnel, communities and the environment, while enhancing the productivity and prosperity of the enterprise. It takes a dedicated and deliberate level of commitment and vision on the part of refinery owners and operators to leverage this smart enabling technology to allow it to transform their facilities into safe and profitable smart refineries. Emerson has taken a leading role in providing smart refinery solutions, including improvements to energy efficiency, safety, health and environmental issues, value addition, cost control, mass and energy balance and overall energy conservation.

The article was published in the previous issue of Offshore World

Tim Olsen Refining Consultant Emerson Process Management Email: Tim.Olsen@Emerson.com

Offshore World | 47 | October - November 2015

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MOST ENERGY COMMODITIES CONTINUE TO DRAG DOWN ENERGY COLUMN (PRICE REVIEW): SEPTEMBER - OCTOBER 2015 Continuing on the past months’ trend, futures prices of most energy commodities moved down in the two-month period of September and October 2015. NYMEX gasoline futures dipped the most by 14.35 per cent on weakness in crude oil prices. On the other hand, ICE EUA (European Union Allowances) futures moved up by 7.33 per cent on strong auction demand.

F

ollowing a surge seen at fag-end of previous month (August), NYMEX (CME) crude oil (light sweet) futures start the month of September at USD 45.41 per barrel, down by 7.7 per cent over the August close. The fall in oil prices was triggered by the release of weak Chinese manufacturing data, thereby dulling the outlook for energy demand. The fall in oil prices was also supported by the release of weak US manufacturing data. Further Iran confirming that it will be increasing its supply by roughly a million barrels a day in the coming couple of years, adding to the existing supply glut kept pressure on oil prices.

Later, oil prices recovered buoyed by a data release showing weekly decline in US oil production and expectations for further stimulus measures by the European Central Bank, which could lift energy demand. Thereafter, oil prices largely exhibited mixed price movement led by mixed factors such as weekly decline in the number of active US oil-drilling rigs as against the lowering of oil price forecasts by Energy Information Administration for 2015 and 2016.

Goldman Sachs cut its price forecasts and warned that the market’s surplus of crude supplies may push prices near USD 20 a barrel. Further, news that Saudi Arabia doesn’t back holding an emergency Organization of the Petroleum Exporting Countries’ meeting aimed at stopping crude’s slide added pressure on oil prices. Nevertheless, data showing a weekly decline in active US oil-drilling

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rigs resisted major fall in oil prices. Further in the month of September, data showing weaker-than-expected industrial production in China and a major decline in Shanghai’s stock market raised concerns over Chinese oil demand, thus putting pressure on oil prices. However, prices continued to trade mixed buoyed by a report showing US crude inventories fell for the first time in three weeks, along with a fall in weekly US oil production. On similar lines, while the US Federal Reserve’s decision to keep interest rates unchanged raised worries about the US economy—and energy demand, upbeat comments on the US economy by Federal Reserve Chairwoman Janet Yellen, at fag end of the month of September again denied major fall in oil prices.

With the onset of the month of October, crude oil prices started to rise. Initially, data showing a weekly drop in the number of active US drilling rigs to their lowest level in more than 5 years, pulled oil prices up. Later, expectations that China may take actions to stimulate its economy, which might help boost energy demand, also helped oil prices move up. The Organization of the Petroleum Exporting Countries (OPEC) forecast of big cuts to oil investments that are expected to ease production and reduce global crude supplies and release of minutes from the US Federal Reserve’s policy meeting implying a further delay in higher interest rates added to bullish sentiments. Further, Russian military operations in Syria

Offshore World | 48 | October - November 2015

FEATURES

raising the risk of oil-flow disruptions in the region pushed NYMEX crude oil futures, to its two-month-high of USD 50.92 on October 10.

Following the registering of two-month-high, oil prices moved down as data showed that members of OPEC continued to pump oil at a breakneck pace. Oil prices then continued to roll down on releases of spate of downbeat economic data from China (trade numbers) and US (retail sales, PPI). Further, a report from IEA (International Energy Agency) stating that the market would likely remain oversupplied next year and US government data showing a hefty weekly increase in US crude stockpiles on the back of a slowdown in refinery activity, kept downward pressure on oil prices. The downward slide in oil prices was briefly interrupted on expectations that OPEC will hold a ‘technical meeting’, ahead of its official summit in December, offering a glimmer of hope that the OPEC will take some action to alleviate the market’s oversupply. However, oil prices then quickly took to downtrend again as a data released showed China’s economic growth fell to its slowest pace since the financial crisis, raising concerns about the outlook for energy demand. Thus, rising US oil inventory levels, lingering concerns over a global supply glut and weakening demand kept oil prices on south-bound trail. Later, US government’s announcement of plans to sell millions of barrels of oil from its Strategic Petroleum Reserve – raising concerns of adding to supply glut, pushed NYMEX crude oil futures to month-low of USD 42.58 on October 27.

At fag-end of the month, with ample oil supplies in the market and low oil prices, expectations for oil production cut grew with cancellations of major projects by oil companies. This along with a data release showing a weekly drop in the number of active US oil rigs, led to some recovery in oil prices. Finally, NYMEX crude oil futures closed the month of October at USD 46.59, down by 5.30 per cent in the two-month period of two-month period of September-October.

Like crude oil, futures prices of oil derivates such as heating oil and gasoline (both traded on NYMEX-CME platform) also moved down in the two-month period of September-October 2015. While, NYMEX heating oil futures prices declined by 10.41 per cent; NYMEX gasoline futures prices plummeted by 14.35 per cent with the end of summer-driving season and the onset of weak seasonal demand

period. The other major energy commodity, NYMEX natural gas futures prices moved down by 13.69 per cent in the two-month period of September-October.

Like over past few months, a consistent rise in weekly US natural gas inventory levels kept natural gas prices on downtrend. Moreover largely warmer-than-usual weather forecasts for major parts of US - in turn dampening demand sentiments for gas, which is heavily used for heating purpose in US households, added to the decline in gas prices.

Like other energy commodities, ICE Rotterdam monthly coal futures prices also moved down by 4.55 per cent in the two-month period of September and October.

Slump in demand especially from China along with mounting environmental regulations, low natural gas prices and a strengthening US dollar kept downward pressure on coal prices. Finally in the emission segment, EUA futures traded on the ICE platform once again bucked the general downtrend and instead moved up by 7.33 per cent in the two-month period of September-October, boosted by strong auction demand. Meanwhile, final legislative stage for the Market Stability Reserve (MSR) – that will reduce auction supply by 12 per cent per year of the total over-supply - has been completed as the MSR amendment to the EU ETS directive was published in the Official Journal of the European Union. This now means all the stages to become part of EU law are complete and the MSR will start as planned in January 2019 bringing to an end of about 2 year process.

(The views expressed by the authors are their personal opinions.)

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

Offshore World | 49 | October - November 2015

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MARKETING INITIATIVE

Adrian Park Global Executive Director - Owner Operator Solutions Intergraph PP&M Email: Adrian.park@intergraph.com

PLANT SAFETY IS NOT A GAME

The Role of 3D Simulation in Plant Workforce Training

I

ndustrial plants contain many potential hazards. Toxic materials are handled with high temperatures and/or pressures. The equipment often requires large amounts of energy. Properly training plant staff is of paramount importance to ensure safe and sustainable plant operations and is one of the most critical elements in Process Safety Management standards such as OSHA 29 CFR1910 119 (2000), BOEMRE (30 CFR Part 250 Subpart S, 2011), Center for Chemical Process Safety – CCPS (2007), and others.

Because plant workers can come into contact with a wide variety of substances and have to work with many different pieces of equipment, training in the real environment has to be handled with extreme care. The main cause of process industry accidents today is still human error.

In addition to ensuring in-depth but safe training, owner operators must tackle another large challenge; the current generation of facility workers is aging and approaching the end of their working careers while a younger generation of new employees enters the plant’s workforce. With this, the need for and volume of staff training and knowledge transfer is rapidly increasing.

Furthermore, as in any learning environment, the approach and methods used for training have to be adapted to the audience to ensure good learning results. The younger generation of plant staff belongs to the computer-savvy gaming generation.

Why not leverage their knowledge of computers and gaming for training simulation in the industrial plant environment? A simulated training environment also addresses the issues of safe training and high volumes of training. We could say that an operator training system is to a plant operator what a flight simulator is to a pilot. The introduction of 3D simulation using 3D models or laser scans has raised the game several levels.

Highly Realistic Experience

freely navigable, realistic and physics-aware. The 3D representation of the plant can either be based on a 3D model or a laser scan complemented by high definition photographs. They include powerful, user-friendly features and functionality to visualize plant operation and create scenarios to immerse trainees in a highly realistic training experience. This enables companies to optimize and manage staff training and certification and plan and simulate numerous production support tasks in a risk-free environment before the trainees need to be exposed to plant hazards that may occur whilst physically performing the task.

The more realism in training scenarios the more effective the training. According to Paul A Roman, Royal Canadian Army, the ‘Serious Gaming’ (SG) approach with simulated training solutions has led to significantly improved training results in terms of time spent, final scores, and costs (see Table 1).

Amount of SG

No SG

5 % SG

45 % SG

Time

6 weeks

5.5 weeks

3 weeks

Final Scores

75%

83%

100%

Costs/Field Exams

6

4

Note: Games – Just How Serious Are They?, Interservice/Industry Training, Simulation, and Education Conference (I/ITSEC) 2008

Creating the Training Field How does it work? A 3D CAD model or a set of photorealistic laser scans are imported to set up the 3D/virtual representation of the facility that needs to be covered for training. Once a 3D model is imported, the model is immediately physics-aware – meaning that equipment, facility structures, and human characters interact with each other as they do in the real world. To increase realism, various effects, such as materials, particles or light/shadows can be applied. Equipment and instrumentation can be mapped to drawing, P&IDs, operations and maintenance procedures, or inspection and emergency response procedures.

Increasingly 3D-based training simulation solutions provide a highly immersive and interactive training experience for industrial plants. These real-time, high-fidelity simulation solutions, provide a wide range of simulation, training and engineering solutions to the power generation, oil and gas, chemical and manufacturing industries can be used be used by plant instructors, operators, engineers, maintenance staff, inspectors and planners.

Users can also create and add photorealistic, custom-made equipment into the 3D/ virtual representation, including welding machines, locks, switches, transmitters, scaffolding, etc. These custom-made and placed objects immediately become part of the facility and are available to use in the configuration of training scenarios.

Best in class solutions also include a fully configurable dynamic animation system and particle effects system, including steam, fire, foam, water, bubble or sparks.

These tools are permanently improving their features and the best ones in the market currently offer 3D representation of the full plant that is fully interactive,

3D models of hoists and cranes can be configured based on design criteria to allow the trainee to activate standard hoists/cranes that are present in a 3D model to

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Offshore World | 50 | October - November 2015

MARKETING INITIATIVE simulate the removal or insertion of equipment or perform site layout planning for outages, etc. If high-detail mechanical 3D models of equipment are available, then these can be included to provide assembly/disassembly scenarios.

The trainee is represented in the software by a realistic-looking human character (avatar) that is fully controllable by the user to be dressed with appropriate PPE, crawl/crouch/walk/jump/run around the plant and perform actions in a physically realistic way.

Administrators can assign access levels to users in terms of the content and functionality available.

This prevents unauthorized users from making configuration changes. It also ensures that a trainee only has access to relevant training content.

Building a Set of Scenarios One of the most advanced 3D training simulation solutions, Samahnzi 3D PACT, offered through Intergraph, provides a user-friendly way to develop procedures in a Microsoft® Excel®-type interface.

No programming or scripting is required to compile or execute procedures.

For each procedure, the user simply lists the objectives of the procedure and the steps/ actions required to achieve each objective. Through 3D PACT’s unique “Challenge” engine, the procedure instantly becomes an interactive, dynamic scenario.

The different activities within a training scenario can consist of one of a combination of, among others, identify equipment; perform any action on equipment; reach target locations (e.g. Locating Equipment, Define Evacuation Areas, Routes/Paths to follow, etc.); avoid restricted/unauthorized areas; define triggers for particle effects and physics-driven effects, as well as actions by other workers on the facility to assist or interfere with the trainee’s objectives; define and interact with other workers in the facility; exert and visualize damage to the trainee as well as other workers as a result of incorrect actions; update third-party interface values bi-directionally (typically simulation software); define required personal protective equipment (PPE) to be worn to perform an action; configure tasks to be executed in parallel, as well as unforeseen events to occur at any stage while a trainee executes a procedure, to test decision-making and reaction-under-pressure ability; define detailed informative or instructional messages that depend on whether the scenario is run in ‘tutorial’ or ‘test’ mode; define reusable multiple-choice questions; animate equipment based on trainee actions and/or the 3rd party simulation interface; perform a crane operation to move equipment, or simply an action to move equipment manually to a designated area or define time limits for reacting and completing an objective in a certain time.

Training modules may be configured to include dynamic animations (i.e., coloring components based on process parameter values) and particle effects (i.e., fire, water/steam/foam flow, smoke) running standalone or coupled to a third-party simulation engine to provide trainees with an in-depth view and insight into process dynamics under normal and abnormal operating conditions.

The software can integrate with any third-party simulation system via OPC or a proprietary interface to drive dynamic animations and particle effects and offers a quick compilation and testing of new operating, maintenance, inspection and emergency procedures for new-build facilities.

3D PACT allows much quicker and more accessible navigation around a 3D plant compared with walking around the physical plant. For plants that are laser-scanned and have Leica TruViews, the user can easily navigate between camera locations, zoom in and out, and also create custom groups of camera references to make large facilities with many camera locations more manageable and more easily navigable.

The execution interface includes Test or Tutorial modes and a full online Trainee Management and Reporting (TMR) system. Instructors and Subject Matter Experts (SMEs) can create training programs (by grouping relevant procedures together), assign training programs to trainees, and track trainees’ progress and performance via the Web. The system can be integrated with legacy Learning Management Systems (LMS) if required.

Among the multiple and broad application areas, two can be highlighted here: Inspection and condition monitoring training and planning, and emergency response training. Performing planning and preparation for inspections from a desk not only saves time, but it also offers a risk-free environment for workers to practice and gain confidence to perform inspections and condition-monitoring tests.

Through a remote database connection, employees can further monitor real-time plant status and operational data and gather visual feedback of equipment status while on the road and away from the facility. The lock-out/tag-out feature makes equipment safe for work/inspection, ensuring trainees know exactly where the isolation points are.

Furthermore, when it comes to emergency response training, simulation of reallife situations becomes essential, not only because addressing dangerous hazards properly and timely saves plant assets and operation, but also because it primarily and fundamentally saves lives. The software helps companies create awareness for potential threats or unsafe situations, including workers making dangerous actions or performing work in an unsafe manner. In addition, companies can evaluate whether emergency response personnel know which equipment to use and which procedures and routes to follow during emergencies.

In the 3D-simulated environment, trainees can easily visit areas of the plant that may be physically or logistically difficult to access (due to heat, noise, poor access/ egress, etc). This allows them to visit frequently and become familiar with these areas that they may have otherwise avoided.

3D training simulation solutions allow instructors and supervisors to train and evaluate staff more efficiently and effectively than ever before, and empower them to quickly determine staff proficiency and identify skills that need to be improved.

Simulation training has become vital for preventing incidents and accidents in many industry sectors, and plant operators are not foreign to this trend. Simulation training also improves process control, resulting in higher throughput and quality with less downtime. Maintenance is reduced because equipment is operated closer to specifications. Costly errors and incidents can be minimised or eliminated with the right training plan and equipment, of which process simulation is a key and cost/effective component. Most importantly, trainees experience an enjoyable, highly immersive, and engaging training experience resulting in faster and better training results, all at lower cost.

(This article was originally published in Hydrocarbon Engineering)

Offshore World | 51 | October - November 2015

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AVOID AN OUTAGE WITH NEW HYDROGEN LEAK DETECTION TECHNOLOGY Maintenance of hydrogen-cooled generators is critical for the safe and efficient operation of a power plant. Finding and repairing hydrogen leaks from the cooling system is one aspect that can require exhaustive searches on components, valves, fittings, or other locations. Traditional methods for hydrogen leak detection tend to be unreliable at finding the source of the leak and better at finding a general area where hydrogen is present. The advent of optical gas imaging cameras has improved the efficiency and performance of leak detection a great deal. With the addition of a dedicated thermal imaging camera for CO 2 leak detection, utilities now have a way to efficiently find hydrogen leaks while using CO 2 as a tracer gas.

T

he operation of an electric power generator produces large amounts of heat that must be removed to maintain efficiency. Depending on the rated capacity of the generator, it might be air cooled, hydrogen cooled, water cooled, or in the largest capacity generators, a combination of water for the stator windings and hydrogen for the rotor. Hydrogen cooling offers excellent efficiency thanks to low density, high specific heat and thermal conductivity. However, hydrogen is highly combustible when mixed with air and can be dangerous if the concentration level builds in an unwanted area. Turbine generators will leak some hydrogen during normal operation and rely on proper ventilation to keep the hydrogen levels from being a safety and explosion risk. Thus, hydrogen gas safety is critical for power plant operators.

avoid unscheduled outages, but up until now they were limited in the ability to find the source of a leak.

Hydrogen molecules are very light, and small, and therefore hard to contain.

Between outages, the wear and tear on valves, seals, and equipment can allow large leaks to form and hydrogen levels to build in areas that could impact plant safety. The amount of hydrogen added each day is carefully monitored. An increase in make-up hydrogen would need to be investigated to find the source of the leak.

Traditional Detection Methods Methods for detecting leaks range from using a soapy solution to create bubbles on each potential component to using microelectronic hydrogen sensors (sniffers) to detect hydrogen over a wide area. The soapy solution is sufficient for checking a single component but checking for a leak in an unknown location could take weeks.

Also, this method only works for tiny leaks since too much hydrogen flow will push the solution aside without forming bubbles. The sniffer is a hand probe which produces an audio-signal when in proximity of a leak. Although this is a relatively affordable detection method, the sniffing test has some drawbacks. Generators are well ventilated. This can dilute the hydrogen unless one is in close proximity to the source. Ventilation airflow can also move the hydrogen quite far from the source leading to “hits” without adequately narrowing down which component needs repair. Sniffers do not allow operators to see the leak. There is always some guesswork involved and time lost in the search for the source of the leak.

Traditional methods for LDAR tend to be slow and may not find the leak quickly enough to avoid a shutdown. A shutdown period could last two to three weeks, with multiple days dedicated to leak detection alone. The cost associated with an unscheduled shutdown can run into the millions of Dollars for an electric utility.

The industry would prefer to perform Leak Detection and Repair (LDAR) online to

A New Approach As a more recent evolution in gas detection technology, infrared cameras have become much more popular with maintenance teams. Infrared or thermal imaging cameras as they are also called have been used successfully to detect insufficient insulation in buildings or find heat-based safety hazards in electrical installations.

Thermal

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Thermal (HSM mode)

Offshore World | 52 | October - November 2015

Visual

MARKETING INITIATIVE

Hydrogen gas safety is critical for power plant operators.

Optical Gas Imaging with thermal cameras came into use a few years ago, using SF6 as a tracer gas. However, some utilities have concerns with using SF6 as a tracer gas due to the cost, Global Warming Potential (GWP 23,000), and, in some cases, restrictions on expanded use of SF6. FLIR Systems partnered with the industry to develop a new generation of optical gas imagers using a tracer gas that eliminates those concerns. The new FLIR GF343 optical gas imaging camera uses CO 2 as a tracer gas, which is readily available at generating stations. CO 2 is inexpensive, has a much lower GWP, and much fewer restrictions vs. SF6 on use.

This will allow broader application of OGI for finding leaks. Because only a small concentration of CO 2 (generally 3-5%) needs to be added as a tracer gas to the hydrogen to make leaks visible to the OGI Camera, the purity level of the hydrogen in the turbine is maintained and normal generating operations are allowed to continue. Engineers have a new tool to use in the FLIR GF343 to find the source of leaks without a shutdown.

Detecting CO2 Tracer Gas By adding a small concentration of CO2 (< 5%) as a tracer gas to the hydrogen supply, the generator will still operate at a safe and efficient level. This allows the operator and maintenance teams to monitor and check for hydrogen leaks during full operation.

During tests in the US and Italy it was proven that the FLIR GF343 can visualize a small amount (~2.5%) of CO2 as a tracer gas in the system when there is a leak, therefore helping maintenance crews find and pinpoint leaks, tagging them for repair during shutdown, or for more immediate repair of any significant leaks.

The benefits which the GF343 has to offer over other detection technologies, is that leak detection can now be performed under full operation, therefore saving time and money by reducing shutdown time. Shutdown time could be reduced by two or even three days and for each day of shutdown costing ~$80,0000- 100,000 (depending on type and size of generator), the payback and return of investment

Optical gas imaging cameras allow you to detect even small leaks from a safe distance.

by using CO2 as a tracer gas and the FLIR GF343 CO2 camera is significant. But small leaks are not only very frequent; they can also turn into large leaks. With the FLIR GF343, maintenance teams can limit the atmospheric hydrogen concentration below the explosion limit in time.

How the FLIR GF343 works?

The FLIR GF343 camera uses a Focal Plane Array (FPA) Indium Antimonide (InSb) detector which has a detector response of 3-5 μm and is further spectrally adapted to approximately 4.3 μm by use of cold filtering and cooling of the detector by a sterling engine to cryogenic temperatures (around 70°K or -203°C). The spectral tuning or cold filtering technique is critical to the optical gas imaging technique and, in the case of the FLIR GF343 this makes the camera specifically responsive and ultra-sensitive to CO 2 gas infrared absorption. Practically, the background energy, such as from the sky, ground or other sources in view of the camera, is absorbed by the gas. The camera shows this energy absorption by way of thermal contrast in the image. The camera not only shows the spectral absorption but also the motion of the gas, hence you visualize the gas as a ‘smoke’ plume.

The GF343 has an additional frame subtraction technique which enhances the motion of the gas. The High Sensitivity Mode (HSM) has been the cornerstone of detecting the smallest of leaks. HSM is in part an image subtraction video processing technique that effectively enhances the thermal sensitivity of the camera. A percentage of individual pixel signals from frames in the video stream are subtracted from subsequent frames, thus also enhancing the motion of the gas and improving the overall practical sensitivity of the camera and the ability to pinpoint the smallest of CO2 gas leaks, even without the use of a tri-pod.

For more information visit www.flir.com The images displayed may not be representative of the actual resolution of the camera shown.

Images for illustrative purposes only.

HSM is in part an image subtraction video processing technique that effectively enhances the thermal sensitivity of the camera.

A sniffer must be held in exactly the right spot to detect a gas leak. Optical gas imaging cameras can detect gas leaks anywhere within their field of view Offshore World | 53 | October - November 2015

www.oswindia.com

PROJECT UPDATE

Media Barter with gulfoilandgas.com

Projects Database Petrochemical Plants and Refineries

Major Projects in the Middle East, Africa and Caspian Sea

Project

Country

Value ($)

Status

Bahrain Aromatics Plant

Bahrain

-

Study

Sitra Refinery Expansion Project

Bahrain

9,000,000,000

Bidding

Baiji Oil Refinery

Iraq

-

Execution

Bazian Refinery Expansion Phase 3

Iraq

500,000,000

Bidding

Karbala Refinery

Iraq

6,040,000,000

Execution

Lukoil - New Petrochemicals Plant

Iraq

-

Study

Al-Zour New Refinery Project (NRP)

Kuwait

16,000,000,000

Execution

Clean Fuels Project (CFP)

Kuwait

16,834,000,000

Execution

Duqm Refinery and Petrochemical Complex

Oman

6,000,000,000

Bidding

Liwa Plastics Project (LPP)

Oman

5,200,000,000

Bidding

Sohar Bitumen Refinery

Oman

315,000,000

Execution

Halul Island Master Plan

Qatar

-

Bidding

Qafco Fertilizer Plants Revamp

Qatar

-

Execution

Ras Laffan Condensate Refinery - Phase 2

Qatar

1,200,000,000

Execution

Normal-Butanol and Iso-Butanol Plant

Saudi Arabia

534,000,000

Execution

Petro Rabigh - Clean Fuels Project

Saudi Arabia

1,000,000,000

Bidding

Petro Rabigh Refining & Petrochemical Complex - Phase 2

Saudi Arabia

8,500,000,000

Execution

Ras Tanura Refinery - Clean Fuels & Aromatics Project

Saudi Arabia

3,000,000,000

Bidding

Chemaweyaat - Petrochemicals Complex Phase 1

UAE

10,000,000,000

Bidding

DP World - New Bulk Liquids Terminal

UAE

-

FEED

IPIC - New Fujairah Oil Refinery

UAE

3,500,000,000

Bidding

Ruwais Refinery Expansion (RRE)

UAE

10,000,000,000

Execution

Africa

Country

Value ($)

Status

Sonatrach - Paraxylene Crystallization Plant

Algeria

-

Study

Tiaret Oil Refinery

Algeria

6,000,000,000

Execution

Lobito (SonaRef ) Refinery

Angola

8,000,000,000

Execution

Soyo Refinery

Angola

-

Study

Middle East

www.oswindia.com

Offshore World | 54 | October - November 2015

PROJECT UPDATE Cameroon Ammonia Urea Fertilizer Plant

Cameroon

1,400,000

Study

Cameroon Atlantic Refinery

Cameroon

-

Study

Assiut Refinery Expansion

Egypt

135,000,000

Execution

Bio-Ethanol from Molasses Project

Egypt

135,000,000

Planning

Full Conversion Hydrocracker Complex

Egypt

2,100,000,000

Planning

Midor Refinery New Expansion

Egypt

1,300,000,000

Study

Tahrir Petrochemicals Complex

Egypt

7,000,000,000

Execution

Gabon Ammonia Urea Fertilizer Project

Gabon

1,300,000,000

Execution

Atwereboanda LPG Storage Facility

Ghana

200,000,000

Study

Equatorial Guinea Fertilizer

Guinea

-

Study

Kenya Petroleum Refineries Limited (KPRL) Mombasa Refinery

Kenya

17,000,000

Execution

Mellitah Complex

Libya

-

Execution

Mohammedia Refinery Rehabilitation & Expansion

Morocco

816,000,000

Execution

Ibeno Petrochemical Complex

Nigeria

1,500,000,000

Execution

Olokola Dangote Oil Refinery

Nigeria

9,000,000,000

Execution

Coega (Mthombo) Refinery

South Africa

10,000,000,000

FEED

Mnazi Ammonia/Urea/Methanol Project

Tanzania

-

Study

Hoima Oil Refinery

Uganda

2,500,000,000

Execution

Caspian Region

Country

Value ($)

Status

Baku Heydar Aliyev (Azerneftyanajag) Refinery Upgrade

Azerbaijan

-

FEED

Oil, Gas Processing & Petrochemical Complex (OGPC) Project

Azerbaijan

7,000,000,000

FEED

Sumgayit Polypropylene Plant

Azerbaijan

373,000,000

Bidding

Bandar Abbas Refinery Upgrade

Iran

300,000,000

Execution

Chabahar Petrochemical Complex

Iran

20,000,000,000

Execution

Damavand Petrochemical Complex

Iran

-

Execution

Kavian Petrochemical Complex (Olefins 11)

Iran

942,000,000

Completed

Kharg Oil Terminal

Iran

-

Execution

Lorestan Petrochemical Complex

Iran

-

Execution

Mahabad Petrochemical Complex

Iran

-

Execution

Morvarid Petrochemical (5 Olefins) of Assalouyeh

Iran

-

Execution

Persian Gulf Star Gas Condensate Refinery (PGSCR)

Iran

2,600,000,000

Execution

Siraf Refining Park

Iran

3,000,000,000

Execution

Atyrau Refinery Upgrade

Kazakhstan

1,040,000,000

Execution

Kazakh GTL Plant

Kazakhstan

50,000,000

Study

Shymkent Refinery Upgrade

Kazakhstan

680,000,000

Execution

Afipsky Oil Refinery

Russia

-

Execution

Far Eastern Petrochemical Company Construction (FEPCO) Project

Russia

5,000,000,000

Study

Moscow Refinery Upgrade

Russia

-

Execution

Nizhegorodnefteorgsyntez Refinery Upgrade

Russia

1,698,600,000

Execution

Ufa Refinery Upgrade

Russia

-

Completed

Yaro-Yakhinskoye Field

Russia

-

Execution

th

Offshore World | 55 | October - November 2015

www.oswindia.com

PRODUCTS

BASKET FILTERS & STRAINERS Basket filters and strainers will permit the straining and filtering of a wide variety of fluids to retain solids of almost any size. All baskets are easily removable and cleanable.

Basket strainer elements can be offered in single cylinder, double cylinder, multi-cylinder and pleated design depending upon requirement of application. They are constructed of filter housing, filter element supported with perforated cage, positive sealing arrangement to avoid any bypass and choice of end connections.

For details contact: Filter Concept Pvt Ltd 302 Aalin, Opp: Gujarat Vidhyapith Ashram Road, Ahmedabad, Gujarat 380 014 Tel: 079-27541602, 27540069 Fax: 91-079-27540801 E-mail: engg2@filter-concept.com

ABR AUTOMATED BREAKTHROUGH ANALYZER Hiden Isochema offers ABR automated breakthrough analyzer, which complements their existing larger scale breakthrough reactor systems. The ABR is designed to meet the needs of researchers wishing to characterize the gas separation performance of novel materials, such as metalorganic frameworks (MOFs), zeolitic imidazolate frameworks (ZIFs) and covalent organic frameworks (COFs), without the time or expense of synthesizing larger quantities of material. Breakthrough curve measurement allows high-throughput screening and testing of adsorbents, for a wide range of separation processes including CO2 capture and storage, the purification and recovery of noble gases, natural gas and biogas upgrading, toxic gas removal and air separation.

The ABR is a dedicated breakthrough analyzer, fully automated and supplied with an integrated close-coupled quadrupole mass spectrometer. Different configurations are available to suit research-scale samples, with bed volumes from 2 to 20 cc.

Up to 6 gas inlets are available as well as a dedicated purge stream. Flow rates are selected to suit the specific applications, and the ABR includes an ultra-low dead volume switching valve. Options include an upgrade for operation at pressures up to 50 bar and an integrated vapour generator module for gas-vapour operation.

The breakthrough data obtained are complementary to the adsorption-desorption isotherms measured using their IGA, XEMIS and IMI sorption analyzers.

For details contact: Hiden Isochema Ltd 422 Europa Boulevard Warrington WA5 7TS, U.K. Tel: +44 (0)1925 244678 Fax: +44 (0)1925 244664 E-mail: cwardropper@hidenisochema.com / info@hidenisochema.com www.hidenisochema.com www.oswindia.com

SOLUTIONS FOR SHIPBOARD CRANES Winch gears and slewing gears are offered by Bonfiglioli for marine cranes such as cargo cranes, utility cranes, hose handling cranes, etc. Bonfiglioli´s Trasmital 700 Series with hydraulic drive is a standout in the company´s portfolio of mobile machinery. The plug-in 700C design is compact and light with gear train integrated into the winch drum. The brake can be integrated inside the gearbox or mounted externally, with common lubrication of the gears. Compact electric-driven variations have been developed as well. Slewing gears are offered from the Trasmital 700T and 300 Series, with integrated pinion and detached pinion respectively. The modular design of these two product Series allows almost unlimited product configurations, one to four gear stages, and hydraulic and electric driven variations, as well as in-line or right angle configurations. The 700T is offered with integrated carburized pinion and eccentric mount for allowing gear play adjustment with the slewing ring toothing. The 700TF design, with single spigot installation, and 700N design, with double support points, are available throughout the full range. Selection of suitable products is in compliance with FEM classification rules of the mechanism.

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

MARINE AND OFFSHORE GEAR SOLUTIONS With its comprehensive product range, Bonfiglioli is a onestop provider of cutting-edge marine and offshore gear solutions that come with the highest certifications and offer unparalleled reliability for harsh marine environments. The company offers diverse solutions for lifting, pulling and slewing machinery for marine and offshore applications like shipboard cranes, offshore cranes, deck machinery, azimuth thrusters and pipe layers. Products include planetary gearboxes, bevel helical and parallel shaft gearboxes, electric motors and frequency controllers. They have been assessed by major Classification Societies like ABS, DNV, LR and can be delivered with a 3.2 Certification in all major Classes and are classed with full traceability of the load carrying components. Bonfiglioli has also developed a specific range of gearboxes for jacking machinery with rack and pinion design, intended for jack-up drilling rigs, service liftboats, accommodation and windmill installation vessels, For details contact: Chem Seals Engg Pvt Ltd 10 Sidhapura Indl Estate Gaiwadi Lane, Off S V Road Goregaon (W), Mumbai 400 062 Tel: 022-28712765, 28772286 E-mail: chemseals@chemseals.com

Offshore World | 56 | October - November 2015

PRODUCTS AUTO BACKWASH FILTER PRESSURE VESSELS FOR LIQUIDS & The automatic self-cleaning auto GASES backwash filters Type PRVC are capable of filtering any solid particles larger than the specified degree of filtration. The water or fluid enters the filter inlet nozzle and flows from inside of filter elements to outside.

The dirt particles are collected on the inside of the filter elements. As the dirt level increases the differential pressure between the dirty and clean side increases and when the differential pressure reaches the preset value back-flushing starts automatically.

In the manual mode back-flushing (cleaning cycle) is activated by means of adjustable timer. During the cleaning or back-flushing cycle two signals are issued by the control panel, one actuates the motor, the other bottom valve.

Geared motor rotate the internal arm under each filter element at the same time valve opens causing a temperary reverse flow to accomplish the cleaning of dirty filter element and removal of accumulated dirt to drain through bottom valve.

Most suitable for cooling tower water filtration (side stream filtration), river water filtration, process water filtration, sea water filtration, filtration before RO. It finds application in power station, process industry, steel industry, sewage treatment plant, environmental technology, mining, paper industry, machine to industry, etc.

For details contact: Sharplex Filters (India) Pvt Ltd R-664 MIDC, TTC Indl Area Rabale, Navi Mumbai 400 701 Tel: 022-69409850, 69409860 E-mail: sharplex@vsnl.com Website: www.Sharplex.Com

ADJUSTABLE PRESSURE REGULATOR FOR HIGH FLOW-RATES Adjustable pressure regulators for high flow rates are regulators having wider outlet pressure range. The outlet pressure can be easily adjusted by rotating the knob of spring adjusting screw. By rotating the knob anticlockwise the outlet pressure is reduced and by rotating it clockwise the outlet pressure is increased. These regulators are mainly used as first stage pressure regulator in the LPG/ natural gas pressure reducing system.

For details contact: Star Gas Service G-30, Express Tower, Azadpur Comml Complex New Delhi 110 033 Tel: 011-27682643, 27677160, 27670185 E-mail: stargasservice@gmail.com / rajesh@stargasservice.co.in

Innovative Engineers offers pressure vessels for liquids and gases using premium grade stainless steel sourced from known dealers. These SS pressure vessel can also be customized as per the customer’s requirement and presented at the best rates in the industry. These pressure vessels are widely used to store gases and liquids at the desired pressures.

For details contact: Innovative Engineers S No: 821 / 2, Charholi B K B/h Maharashtra Warehousing Corpn, Nasik Road, Tal. Haveli Pune, Maharashtra 411 038 Tel: 020-20280144, 25388341

LPG SENSOR Conceptronics offers LPG sensor to the clients. The excellent technology used by this LPG Sensor is responsible for its accurate performance for long time period. Their experts have designed this in the precise manner and operate with the help of analogue signals.

This is completely compatible and could be availed in excellent technical specifications.

For details contact: Conceptronics 8B Raja Naba Krishna Street Kolkata 700 005 Tel: 033-25554650

GAS FLOW METER Heatech Engineers offers range of gas flow meters used to test the flow of the gas in various pipe equipment and other gas-oriented furnaces or industrial appliances. This meter is used in testing purposes, especially on various gas burners and gas equipment to ensure that the required amount of gas-pressure is obtained.

For details contact: Heatech Engineers 514, Palaniyandavar Nagar, Ranga Layout 2 Backside Nallampalayam, Ganapathy Post Coimbatore, Tamil Nadu 641 006 Tel: 0422-6576521

Offshore World | 57 | October - November 2015

www.oswindia.com

EVENTS DIARY

OSEA2016

Iran Oil & Gas Summit

Date: January 25-16, 2016 Venue: Tehran, Islamic Republic of Iran Event: With tens of billions potentially up for grabs, Iran is now one of the world’s prospects to lead in the oil and gas industry, capitalizing on the needed technologies to increase oil and gas productivity. The Iran Oil and Gas Summit will provide opportunities to gather with some of the world’s prominent people from the Energy Sector, who are behind potential multi billion-dollar investments. Moreover, the summit will pave the way to limitless networking possibilities with its IOGS Networking Lounge. This event will be a gateway to discover the plans of the Islamic Republic of Iran for its oil and gas reserves and its possibilities. Attendees will also have a chance to participate in open forums with Iran’s legal and regulatory policy-shapers, as the giant lurks to potentially return to the market. The conference is aimed at high profile international audience and senior figures from oil, gas, and petrochemical sectors, including strategists, analysts, acquisition executives, influential leaders and decision-makers. Senior executives, Policy and procurement officials from within the Iran Oil Ministry and other government companies including International leading experts to briefly examine the political issues, financial concerns and legal challenges facing the industry.

For details contact: Syllabus Events Ltd Coleen Lopez Media Relations Phone +971.4.269.8878 | Email: Media@sev.ae www.iranogs.com

5 th East Africa Oil & Gas Expo 2016

Date: June 10-12, 2016 Venue: Nairobi, Kenya Event: The 5th 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

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.

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

Oil & Gas World Expo 2016 Date: 3-5 March, 2016 Venue: Mumbai, India Event: Oil & Gas World Expo 2016, the 7 th International will organise by CHEMTECH Foundation, who has been a pioneer in connecting & conceiving international exhibitions & conferences since 1975. The international expo & conference is for aiming to connect, discuss and conclude views of leaders, policy makers, regulatory authorities, service providers of the Indian & Global hydrocarbon industry. Since its inception in 2004, the series of Oil & Gas World Expo has been a big affair of luminaries of global hydrocarbon industry that reflect India’s growing role in the global hydrocarbon industry. The expo will provide a platform to showcase services, technologies, innovations & current & future trends of the entire value chain of hydrocarbon industry ranging from upstream to midstream and downstream.

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/

Offshore World | 58 | October - November 2015

MORE CONTROL WITH LESS RISK Your desire for total control is only natural when it involves critical safety valves or injection mandrels 10,000 feet (3,000 meters) below the sea. But are your control lines and chemical injection lines optimized for corrosive or sour environments?

This is where our Sandvik SAF 2507™ super-duplex stainless tube can help.

Whether you need cut-to-length, grouped, encapsulated or flushed and filled mounted on your own reels, we can deliver to all oil and gas hubs. Are you pushing the limits of well completions? We help you get there.

SMT.SANDVIK.COM

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