Offshore World Dec 2015 Jan 2016 by Offshore World

VOL.13 | ISSUE 1 | DECEMBER 2015 - JANUARY 2016 | US $ 10 | ` 150

OFFSHORE WORLD

INSIGHT INTO UPSTREAM & DOWNSTREAM HYDROCARBON INDUSTRY

www.oswindia.com

DECEMBER 2015 - JANUARY 2016 VOL. 13 ISSUE 1 Mumbai ` 150

CONTENTS

INTERVIEW ‘Stay focussed in India and make a difference to Indian Hydrocarbon Industry’ - P Elango, Managing Director, Hindustan Oil Exploration Company

‘Oil & Gas industry is the second largest after Chemicals facing the problem of corrosion’ - Yatinder Pal Singh Suri, Country Head, Outokumpu India Pvt Ltd

VOL. 13 | NO. 1 | DECEMEBER 2015 - JANUARY 2016 | MUMBAI ` 150

OFFSHORE WORLD R.NO. MAH ENG/ 2003/13269 Chairman Publisher & Printer Chief Executive Officer

EDITORIAL

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

Jasu Shah Maulik Jasubhai Shah Hemant Shetty

‘Within the RSC model, as the contractor keeps earning, the Government gets progressively higher revenue’ - Raghav Jindal, Managing Director, Jindal Drilling & Industries Limited

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 Umesh Chougule, Arun Parab Dilip Parab V Raj Misquitta (Head), Arun Madye

‘H-Energy is aiming to create a competition-based natural gas market in India’ 26 - Darshan Hiranandani, Manging Director, H-Energy

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

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

‘Oil & Gas EPC industry to look forward to India in the years to come’ - Vivek Venkatachalam, Managing Director, IOT Infrastructure & Energy Services Limited

Staying ahead in the Turbulent Time - Arbaaz Malik, Managing Director, Arslan Enginery Limited

Hydrogen Management in Refinery Complex - Amit D Choudhary and Srinivasa Oruganti

Appraisal of Corrosion Prevention and Control Measures by Corrosion Audit - Anil Bhardwaj

An Industry Response to the Evolving Needs of Subsea Flow Assurance - Spencer Allen

MARKETING TEAM & OFFICES

Mumbai

Ahmedabad

Vadodara

Bengaluru Chennai / Coimbatore

Delhi

Hyderabad

Kolkata Pune

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 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 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 Princebel M Mobile: 09444728035 E-mail: princebel_m@jasubhai.com 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 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 Princebel M / Sunil Kulkarni Mobile: 09444728035, 09823410712 E-mail: princebel_m@jasubhai.com, sunil_kulkarni@jasubhai.com E-mail: industrialmags@jasubhai.com 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/-

FEATURES

Estimation of Each Acid Component in a Mixture of Acids using Conductivity Titration 42 - Jajati Nanda, Anil Patil and Jyoti Waikar First Subsea Gas Compression System in World: Milestone in Subsea Technology - Sanjay Kulkarni

COVER STORY Is India Ready to Embrace Euro VI by 2020? - Rakesh Roy

Jasubhai Media Private Limited

PROJECT UPDATE

TRENDS Products 64

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

Most Energy Commodities Continues to Drag Down 55 - Niteen M Jain & Nazir Ahmed Moulvi

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.

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

Events Diary 66

Offshore World | 4 | December 2015 - January 2016

WE’RE A FULLSTREAM PROVIDER FOCUSED ON KEEPING THE DOWNSTREAM UP AND RUNNING.

S:9.875”

GE brings an innovative and fullstream perspective to break down silos, delivering greater reliability, reduced costs, fewer operational and financial risks, and increased production. Learn how we fuel the future at geoilandgas.com

INTERVIEW

â&#x20AC;&#x2DC;Stay focussed in India and make a difference to Indian Hydrocarbon Industryâ&#x20AC;&#x2122;

Being the first ever Oil Company in private sector participated in the oil & gas exploration in India, Hindustan Oil Exploration Company (HOEC) has built a strong portfolio of assets with operating experience in both onshore and offshore in the country, says P Elango, Managing Director, Hindustan Oil Exploration Company. In an Email interaction with Rakesh Roy, he simplifies that the company is determined to stay focussed in India and emerges as the finest E&P player who will leverage talent and technology to add value and make a difference to Indian Hydrocarbon Industry.

While the lower prices helped India to reduce its import bill significantly and allowed Govt to remove subsidy, domestic E&P activities have slowed down particularly in offshore as no offshore development will be viable at such low oil prices.

www.oswindia.com

Offshore World | 6 | December 2015 - January 2016

The search for cleaner energy begins with long lasting materials

We are the global leader in the advanced material business, with our heritage going back over 100 years to the very invention of stainless steel. Wherever our partners are, we will be there with stainless steel and high performance alloys designed to meet the most extreme demands under the harshest conditions. Because the first step towards a world that lasts forever is making todayâ&#x20AC;&#x2122;s energy solutions as dependable and sustainable as possible.We believe in delivering best in product quality and technical expertise while becoming even better at customer orientation, speed and reliability. Outokumpu wakes every day with the mission to make its long lasting materials as sustainable as possible, because our goal is a world that lasts forever.

outokumpu.com yatinder.suri@outokumpu.com

INTERVIEW Being the first ever Oil Company in private sector participated in the oil & gas exploration in the country and having assets in Assam, Cauvery and Cambay, how does HOEC plan to play its role in India’s Hydrocarbon growth story? HOEC, founded as the very first Independent Oil and Gas company in private sector by the legendary Late Shri H T Parekh, has just completed 25 years of listing in BSE. Over the years, HOEC has built a strong portfolio of assets with operating experience in both onshore and offshore. Since I joined in Feb 2015, our strategy has been to focus first on onshore assets in Assam and Gujarat, build a strong geotechnical team to revive the offshore assets (when the price cycle turns) and leverage opportunities that an under explored Indian Sedimentary Basins and expanding gas sector presents in the context of growing Indian economy. We are determined to stay focussed in India and emerge as the finest E&P player who will leverage talent and technology to add value and make a difference to Indian Hydrocarbon Industry. How has the falling crude oil price affected the Indian hydrocarbon industry in whole and the profit margins of HOEC? The falling crude oil has not only adversely impacted the global oil and gas industry; it is now beginning to impact the global economy too. While the lower prices helped India to reduce its import bill significantly and allowed Govt to remove subsidy, domestic E&P activities have slowed down particularly in offshore as no offshore development will be viable at such low oil prices. Impact on HOEC margin has been minimal as our production base is low and we produce and sell more gas than oil at fixed contract prices to GAIL. It certainly helps to be a low cost operator and we are generating positive operating margins from every field on production. HOEC’s Q3 result of the current fiscal shows that the company is slowly recovering from its past losses. What are the growth strategies HOEC followed to reach here? How do you plan to maintain the profit margins in future? Yes! We began the journey at the beginning of 2015 with ` 30 Crores as Cash on hand in the Working Capital and ended the year with ` 62 crores.

Can you please detail more about Dirok gas field on its production and development status so far? The Dirok Gas development project is very robust. We already have three wells drilled that require to be completed and produced. We will also be drilling one new well and will set up a modular Gas Processing Plant away from Eco Sensitive Zone by laying required pipelines. Approved Field Development Cost for this project is ` 500 crores and we have seen actual costs are below budget estimates as services sector is hungry for work. We are committed to develop this project on a fast track basis, so everyone in HOEC is working as one team to achieve our one goal of delivering first gas in by end of FY 2016-17. Since the gas will feed to the flag ship Brahmaputra Gas Cracker Project Limited (BCPL), there is a greater support to fast tracking this project from all stakeholders such as DGH, Ministry of Petroleum, Government of India, the State Government of Assam and JV partners Oil India and IOC. With the announcement of auctioning 69 marginal fields, the government has proposed changing policy regimes like revenue sharing model, free natural gas pricing, uniform licensing policy, OALP, etc for future oil & gas field auctions. What is your view on it? The changes proposed by the Government under the Marginal Field Policy are well timed and would stimulate interest in domestic oil and gas sector during these challenging times. I see these changes as a precursor to similar reforms for future NELP rounds or OALP - free market pricing for natural gas has been one of the vocal demands of the industry. Is HOEC planning for auctioning & developing marginal fields in the proposed terms? HOEC sees the marginal fields bidding under the revised terms as a great opportunity to build a portfolio of low risk and synergetic blocks and will be keen to participate subject to detailed terms that are yet to be announced. It is important for the Government to ensure that burden of past costs on these fields are not passed on to the new bidders. At these price levels, any such move would make several fields unattractive and the resources will remain untapped. Can you please elaborate more of your comment on ‘Drill in India’ campaign under the umbrella of ‘Make in India’ where you said: “the country must become price maker, not price taker”?

What has helped us is our relentless focus on; 1) Progressing the Assam Development without increasing our cost base; 2) Increasing cash component in our working capital by securing tax refunds; and 3) Cleaning up the balance sheet through appropriate impairment.

India is home to over 3 million square kilometres of sedimentary basins and over two thirds of the basins have not been ‘fully explored’. All of us know the only way to find oil is to drill wells, more and more of them. India drills less than 1000 wells/year against more than 20,000 wells/year being drilled in USA.

We expect to further improve profit margins by reducing the project costs and deliver First Gas from Assam as promised by end of FY 2016–17. At full year of Plateau Production Dirok field will help to double our revenue.

My point was under the umbrella of ‘Make in India’ policy, if a Drill in India campaign is rolled out, it would energize the drilling services industry and would lead to intensified exploration and fast track development. Large

www.oswindia.com

Offshore World | 8 | December 2015 - January 2016

Make GAS visible! FLIR GF-Series Thermal imaging cameras for gas detection and industrial applications

Conventional leak detection equipment such as a Volatile Organic Compound meters (or sniffers) mean that the operator must visit and test each potential leak site. Using a FLIR GF-Series thermal imaging camera you get a complete picture and can immediately exclude areas that do not need any action. This means you can achieve enormous savings in terms of time and personnel. Another advantage is that systems do not have to be shut down during the inspection. Depending on the model, a wide variety of gas can be detected. All FLIR GF-Series thermal imaging cameras are dual-use systems. They not only allow the user to detect gases. They can also be used for industrial maintenance inspections.

Captured gas leak

Electrical inspection

Gas leak

If you want to have more information about the FLIR GF-Series or any other FLIR thermal imaging camera please contact:

FLIR Systems India Pvt Ltd. 1111, D-Mall, Netaji Subhash Place, Pitampura, New Delhi â&#x20AC;&#x201C; 110034. INDIA Tel : +91-11-4560 3555 Fax :+91-11-4721 2006 E-mail : flirindia@flir.com.hk

The images displayed may not be representative of the actual resolution of the camera shown. Images used for illustrative purposes only.

flir Gas AD A4 25-5-15.indd 1

25/05/15 6:03 pm

INTERVIEW campaigns would attract global service providers, enhance competition, bring down cost of services and would improve operational efficiencies.

BOOK YOUR ADVERTISEMENT

NOW!

According to you, what should be the wish list of Indian oil & gas industry from the upcoming Union Budget in stimulating the sector in the current environment?

3 SPECIAL ISSUES

Overall policy objective has to be: 1) To Increase Oil & Gas Exploration & Production 2) To Develop Greener Gas as a fuel of choice 3) To Promote Oil Services Sector In the context of declining oil and gas prices, financial incentives are certainly required to stimulate investment in domestic oil and gas sector. Cess on domestic crude oil needs to be reduced. Incentives enjoyed by the NELP Block holders should be extended to all blocks including nominated blocks with PSUâ&#x20AC;&#x2122;s. OIDB funds should be allocated to promote Enhanced Oil Recovery Projects and National Gas Grid and to enhance E&P activities in the North East region which is estimated by experts to hold significant untapped hydrocarbon resources. Can you please apprise us the future plans and funding strategy of HOEC whereas ENI, the Italian oil giant, is the companyâ&#x20AC;&#x2122;s main promoter?

February-March 2016

Advancements in Oil & Gas Industry April-May 2016

ENI continues to hold over 47 per cent stake in the company and are our promoters and HDFC holds 11 per cent in the company and has been a consistent investor and a well-wisher.

EPC Special

As ENI our current Promoter has disclosed to the market that they will not be infusing any further capital in to the company. Our strategy is to pick up financially robust projects, de-risk it for execution and raise appropriate capital with committed end use restrictions. This can be either equity or debt after obtaining all the required approval. However, we are neither desperate nor in a hurry to do so.

HSE in Oil & Gas Industry

The ` 500 crores development cost of Dirok Gas Project will be shared proportionately by the respective JV partners according to their Participating Interest. We are now a Debt-Free Company, who is able to meet Operating Expenses with Operating Revenue and is capable of generating operating cash surplus to add to cash on hand. We have now began our journey to turn around the company on the strength of a cleaned up Balance Sheet and we will not look back until we realise our vision, which is to re build HOEC as the finest Independent Oil and Gas Company that transforms the interests of all stakeholders. www.oswindia.com

June-July 2016

For Details Contact Jasubhai Media Pvt. Ltd. Taj Building, 3rd Floor, 210 Dr D N Road, Fort, Mumbai - 400 001 Tel: 022-4037 3636, Fax: 022-4037 3635 Email: industrialmags@jasubhai.com

www.oswindia.com

Offshore World | 10 | December 2015 - January 2016

Setting Standards FLUXUS® F/G721

Advanced Non-Intrusive Ultrasonic Flow Measurement

Bijal Trading Corporation Paras Enterprises OIL CLEANING VAPOUR DEGREASING SOLVENTS FAST CLEANING AND FAST DRYING SILVER, COPPER, NICKEL SILICON BRAZING ALLOYS AND FLUXES For more details:

C/16, Silveroak, S.V. Road, Bhatt Lane, Borivli-West, Mumbai 400 092. Tel.: 022-2801 1616 l Mob.: 09324850989 l Email: rajbai@mtnl.net.in

 Highly accurate and reliable bidirectional flow measurement of liquids and gases over a wide turndown ratio  Bidirectional communication via all common field buses as well as advanced remote diagnostics  Engineered and approved for use in hazardous areas (ATEX, IECEx Zone 2) and at extreme pipe temperatures (-190 °C up to 600 °C)  Highest cost-effectiveness: - No pipe works - No process shut-downs - Virtually maintenance-free  Zero point stable, drift-free and independent of pipe dimensions, material, pressurisation, pipe noise and the medium flowing inside (calibration traceable to national standards)

www.flexim.com info@flexim.com

INTERVIEW

‘Oil & Gas industry is the second largest after Chemicals facing the problem of corrosion’ Today’s Oil & Gas exploration & production is more challenging as service conditions have become increasingly severe with higher temperatures, higher pressures, sour fields (high H 2S content) with high CO 2 levels. All these challenges pose a big demand on safety and require advanced technologies, improved equipment and high performance materials in order to ensure the smooth and especially safe production of oil and gas, says Yatinder Pal Singh Suri, Country Head, Outokumpu India Pvt Ltd. In an email interaction with Rakesh Roy, he illuminates on anti-corrosion materials & alloys of Outokumpu in safeguarding HSE aspects of Oil & Gas industry in details.

Demand for stainless steel for the entire Hydrocarbon spectrum, ranging from onshore to offshore, has been growing in India due to corrosion issues faced and the need to have equipments which do not need a repair shutdown.

www.oswindia.com

Offshore World | 12 | December 2015 - January 2016

TOP Distributors for Semikron / Jean Muller / ELECTRONICON (Germany) Bussmann FUSES, EATON-CUTLER HAMMER & MOELLER / BEI Encoders / CRYDOM S. S. R. in INDIA.

INTERVIEW India is now the third largest steel producer worldwide, however low per capita consumption. According to you, what are the growth drivers for the same and the contribution of Indian hydrocarbon sector in this growth? With crude stainless steel production at 3 million tonne, India ranks as the third largest producer and second largest consumer of stainless steel. The market for 2013-14 was at 2.5 million tonne of which flat products accounted for ~2 million tonne. With a low per capita consumption of 2.1 kg (as against the world average of 5 kgs) there lies a huge potential for future growth. Interestingly, the share of stainless steel production in overall steel production in India is more than 4 per cent, which is much higher than about 2 per cent share globally. But due to low per capita usage the stainless steel sector in India suffers from huge overcapacity and the emerging growth opportunities in infrastructure investments can see huge demand potential to consume the overcapacity over the next few years. Even a growth of 1 kg per capita from the current level of 2 kg can mean a demand surge of 1 million tonne of stainless steel. India will also be riding the wave of growth in all sectors presently including use of stainless steel. It is being considered engine of growth for the economy. The demand for stainless steel is on constant increase in the country due to development of better infrastructure, increasing consumption in various sectors and projects as well as quickly gaining popularity in terms of preference due to its properties like corrosion resistance, aesthetics, low life cycle cost and health & safety aspects. Demand for stainless steel for the entire Hydrocarbon spectrum, ranging from onshore to offshore, has been growing in India due to corrosion issues faced and the need to have equipments which do not need a repair shutdown. Therefore requirements on high-end materials of construction used in hydrocarbon exploration and processing are increasing. More over hydrocarbon currently is the most demanding sector which has created a large market for stainless tanks, pipes, pumps and valves in the country. The demand for corrosion free higher metallurgy materials are on increase in high-end industries including Oil & Gas, Energy, Shipping, Railways, Bridges Desalination, Water & Sewage Treatment and Sea Ports. There is a need to eliminate maintenance costs due to corrosion in these segments and seek right solutions to enhance the life of products, plant, machinery and civil structures as well as human health and safety through hygiene by using suitable grades of stainless steel. Corrosion is one of the outstanding challenging problems in Oil & Gas exploration, processing and pipeline systems, resulted a loss of several billions of dollars & environmental mess. How can be anti-corrosion materials grade safeguarded the interest of the industry in this regard. What are the offerings of Outokumpu to its customers in this direction? India loses more than USD 40 billion a year - about 4 per cent of the size of the total economy - due to corrosion in infrastructure and industry segments. Over the past few decades, corrosive conditions in the Oil and Gas Industry www.oswindia.com

have steadily grown in severity. It prompts a need for efforts to minimise the downtime and failures through better corrosion mitigation practices, most reliable being the use of appropriate grade of stainless steel. Good news is that Government of India has woken up to this reality and signed a vision document with USA with corrosion mitigation as one of the key objectives. With pipelines for transport of natural gas as well as oil being laid decades ago in carbon steel with coatings, corrosion accounts for nearly 20 to 25 per cent of the leakages in pipelines and several other Grade-3 leakages. We have seen corrosion failures leading to explosions and fatalities as well as oil spillage in seas as well as agricultural land. Oil & Gas industry is the second largest after Chemicals facing the problem of corrosion. Worldwide oil companies are using corrosion resistant materials including stainless steel for process gas and oil transportation, piping systems, separators, scrubbers, pumps, manifolds, flowlines and pipelines transporting corrosive Oil & Gas. Duplex grades have become standard in the inner tubing of flexible pipe, and in umbilicals. Not only do the duplex grades protect against corrosion, but they are capable of supporting their own weights in deep water. Over the past few decades, as the oil exploration goes deeper into the sea the corrosive conditions in the Oil & Gas Industry have steadily grown in severity. The offshore oil industry continually pushes oil exploration to greater depths, which leads to higher pressure conditions and high temperatures. It is of prime importance in these industries to select corrosion-resistant materials that meet those tests to achieve long maintenance. In subsea applications, the cost of repairs can be ten times higher than the cost of higher metallurgy materials used initially. This is a very important aspect which needs to be implemented. Outokumpu is the global leader in advanced materials with very wide product portfolio including advanced materials we can offer the most optimal solution for almost all kind of applications. In applications where very high ductility, wide temperature ranges, or specific corrosion features are desired, Outokumpuâ&#x20AC;&#x2122;s austenitic stainless steel and super-austenitic stainless steel grades are often most recommended. Outokumpuâ&#x20AC;&#x2122;s super-austenitic stainless steel grades have shown reliability in resisting highly corrosive environments including sea water applications and for projects requiring high strength. How has the technical challenges of anti-corrosion materials & alloys been changed with the changing global oil & gas business environment. What are the steps Outokumpu has been taken to match the requisites with the changing scenario? World Over including India stainless steel industry is now focussing on highend application segment including the applications in the growing energy sector by supplying its premium grade steel to upcoming challenges in power projects which include nuclear, renewable and fossil energy as well as applications in oil and gas, chemical processing industries, coastal bridges and desalination plants where human safety and process efficiency elements play a key role.

Offshore World | 14 | December 2015 - January 2016

Safety valves for Oil & Gas industry LESER India launches Type 526 IC and 459 IC UV Stamp

Quick Delivery

Durable Design

Key benefits:

+ + + + +

UV-stamped safety valves for Oil & Gas industry Type 526 IC designed according to API 526 standard Type 459 IC compact performance series for thermal applications to complement Type 526 IC API series Globally proven safety valves with German technology in a configuration especially for Indian requirements Very fast and reliable delivery time of six weeks ex works

Read more about the new safety valve Type 526 IC & 459 IC on the LESER India website www.leser.co.in Head office in Mumbai

LESER India 136/137, Sanjay Bldg. No. 3, Mittal Estate Marol, Andheri Kurla Road, Andheri (E), Mumbai - 400 059, India Tel.: +91 22 28532200 Email: info@leser.co.in

Plant in Paithan

LESER India D-3, M.I.D.C. Paithan, Dist. Aurangabad, Maharashtra - 431 148, India Email: sales@leser.co.in

The-Safety-Valve.com

ADVERTISE TO EXPAND

your reach through

INSIGHT INTO THE PHARMACEUTICAL AND BIOTECH INDUSTRIES

For Details Contact

Jasubhai Media Pvt. Ltd. Taj Building, 3rd Floor, 210 Dr D N Road, Fort, Mumbai - 400 001 Tel: 022-4037 3636, Fax: 022-4037 3635 Email: industrialmags@jasubhai.com

INTERVIEW Outokumpu, being the innovator of stainless steel, has biggest R&D centre. There is one for process improvements to offer price advantage and another one for product and application innovations for sustainable advantage. Our sales companies are backed up by product specialists for each segment for our offerings and our customer liaison is coordinated by a well-trained technical expert team and service support to help customers get the greatest value out of using stainless steel on the project.

manifolds, X-mas tree components, flowlines and pipelines transporting corrosive oils and gas.

The high end requirements in critical industries like Oil and Gas, energy generation need high quality stainless steels which form a key material in hostile environments. The oil and gas production is very high on safety where absolute reliability is most crucial. Outokumpu, being the pioneer in product and application innovations, can satisfy stringent requirements for applications in onshore or offshore, upstream or downstream.

Despite efforts to promote renewable resources, oil and gas is expected to continue to be the backbone of energy supply for the decades ahead. As conventional available reserves are largely being exhausted, more difficult fields have to be explored and enhanced oil recovery methods have to be utilised in existing fields in order to keep up with the accelerating demand for oil and gas. The era of easy accessible oil and gas has ended!

Outokumpu’s presence in India is primarily relevant for high-end grades and higher dimensions which are not manufactured in India. Being the oldest and largest stainless steel player in the world, India definitely needs Outokumpu innovations.

Oil and gas production is more challenging today as service conditions have become increasingly severe, e.g.: higher temperatures, higher pressures, sour fields (high H 2 S content) with high CO 2 levels. All these challenges pose a big demand on safety and require advanced technologies, improved equipment and high performance materials in order to ensure the smooth and especially safe production of oil and gas.

Deepwater oil & gas plays an ever-more important role to play in future global oil & gas industry. What are the subsea solutions Outokumpu has provided to the industry? Over the past few decades, corrosive conditions in the Oil and Gas Industry have posed new challenges. The offshore oil industry continually pushes oil exploration to greater depths, which leads to higher pressure conditions and harsher environments. The future of oil and gas drilling could soon be nearly invisible from shore. The ocean floor leads to difficult environments, and in order to safe guard against the high cost of component failure, it has become critical to ensure that the right alloys are chosen for applications within the oil and gas industry. This has created a demand for stainless steel especially Duplex 2205 and other lean as well as super duplex stainless steels. Outokumpu has been a key supplier of stainless steel to the Oil & Gas industry for upstream and downstream applications – from oil and gas production to transport and storage, refineries, LNG plants and petrochemical units. As wells are explored at greater depths, the piping becomes heavier. The superior mechanical strength of duplex stainless steel benefits the industry by allowing for lighter design. Outokumpu pioneered the development of duplex during the past decades catering to more than half of all duplex stainless steel in the world today. Also on the platform, the increased mechanical strength of the duplex grades can be utilized. The most recently developed Outokumpu EDX 2304™ NORSOK Approved which, thanks to enhanced levels of strength and corrosion resistance, is set to deliver significant material savings and lifecycle advantages with lifetime of a platform enhanced to more than 50 years . Outokumpu’s Duplex 2205 and other duplex grades are increasingly the material of choice for process piping systems, separators, scrubbers, pumps, www.oswindia.com

Safety is an utmost of importance in Oil & Gas industry – be it onshore & offshore – in protecting personnel, equipment and environment. Can you please explain Outokumpu’s thought on it in providing materials solutions for the industry?

One of the most sought-after traits of stainless steel is the corrosion resistant property. When a material encounters corrosion process it becomes weak, contaminated and fails to hold its own under a wide array of environments. It becomes a major safety issue. But when the right grade of stainless steel is selected, the damaging effects and costs are eliminated from the process to ensure safety. Other than materials supply, what are the USPs that make Outokumpu a preferred company for Oil & Gas industry? For Oil & Gas companies, Outokumpu comes as natural partner as it has been offering products and applications for the energy industry for decades. Other than material supply, Outokumpu provides Materials testing for optimal grade selection with its extensive experience in testing stainless steels in many environments. The results of many of these tests, covering the most common corrosive elements are available to customers in our Corrosion Handbook. In specific cases, Outokumpu also offers test samples for customer’s own processes and later supporting with evaluation by our specialists in our own corrosion laboratory. These tests, together with our long experience and tradition in the oil and gas industry, ensure that the grade you finally choose is the optimal solution. Outokumpu studies customer needs on the spot, delivering professional help not only in material selection but also in planning, logistics advice and adapted service for optimal products, cost-efficient operations, and deliveries according to the customer schedule. We offer support in welding areas for the new grades with our Welding Handbook.

Offshore World | 16 | December 2015 - January 2016

INTERVIEW Moreover the world needs and deserves innovations that support sustainability. Our products and manufacturing process are acclaimed as the best in class in terms of sustainability. The recycled content of our advanced materials varies between 80 per cent and 90 per cent depending on the grade. The non-thermal energy consumption is also over 80 per cent. Our vision of a world that lasts forever is aided by our ongoing commitment to innovation and the development of lasting customer relationships. How do you plan to steer the growth of the company in India and scaling up the operations? Outokumpu India Pvt Ltd – a subsidiary of Finnish steel major Outokumpu, has been present in India since 2006. We came to India with something that didn’t exist in terms of product forms, grades and applications. In last several years, we have successfully created the market for the new age stainless steel products produced by the company by enlightening the end user and educating the consultants and the decision makers on the competitive advantages they could derive. We have expanded our presence in five locations ie; Mumbai, Pune, Baroda, Delhi and Chennai - all stainless steel intensive regions. Now we are well established in the Indian market with our superior high end products supporting applications in the field of Oil storage, chemical storage, distribution pipelines,

Metro coaches, Railway coaches, Railway wagons, Road and Rail bridges, skywalks, Chemical tanker ships, Food processing and Desalination. Apart from this due to our advanced R&D capabilities, we keep adding new products and applications every year. Stainless steel rebar is another success in India with opportunities for use in coastal and hilly regions. Outokumpu’s presence in India is helping the local manufacturers to learn and upgrade their capabilities to global standards. The end users are delighted to receive personalised and ethical services with cost advantages through education and use of high end grades and higher dimensions which are not manufactured in India. India definitely needs Outokumpu innovations. For many upcoming projects Outokumpu has been identified as an ideal partner due to our global presence, a wide range of high-end grades for Oil & Gas applications with successful track record of reliable performance in various projects abroad. In fact, we fit into the corrosion mitigation mission of India very well since the oil and gas industry in particular will not face problems either on product knowledge, availability and selection of right materials to prevent corrosion. The new Outokumpu is the global leader in advanced materials and helping the world to reduce the pace of consumption of our planet. Thus promoting sustainability and help create a world that lasts forever.

NEXT ISSUE FOCUS: In the backdrop of plunging oil price, it is mandate for Oil & Gas Industry to develop advance technology and application in transforming the future of the oil and gas industry in protecting their profit margins. The current February March 2016 issue of Offshore World is based on “Advancements in Oil & Gas Industry” and will identify the latest technology and application development across – Geological & Geophysical surveys, Seismic Studies, Upstream – exploration , production & field development, Hydrocarbon Processing ; Transportation & Storage; and Refining. We have invited industry experts to share their views through Guest Columns, Technical Articles and Industry Case Studies on promising new technologies & innovations across the entire hydrocarbon segments. To ensure Offshore World continues to meet your needs, we would appreciate in getting your feedback. Please feel free to write us at rakesh_roy@jasubhai.com.

ADVANCEMENTS IN OIL & GAS INDUSTRY Offshore World | 17 | December 2015 - January 2016

www.oswindia.com

INTERVIEW

‘Within the RSC model, as the contractor keeps earning, the Government gets progressively higher revenue’ The depression in International crude oil prices has deeply affected the global Offshore Drilling market on the whole. “While the present conditions are unfavourable for drilling contractors, the market conditions will not remain the same forever. This definitely brings an opportunity to prepare for the future when the market conditions turn in favour of E&P activities,” says Raghav Jindal, Managing Director, Jindal Drilling & Industries Limited (JDIL). He elucidates the current state and growth drivers for Indian drilling market in the backdrop of falling global oil price and the government’s decision of switching policy regime from PSC to RSC, announcement of bidding marginal fields and realign LNG strategy in importing huge LNG, etc. He further details on JDIL’s future plan and international expansion plans, in an email interaction with Rakesh Roy.

The main drivers for the growth of drilling market in India are investing in New Age Technology and Efficiency in E&P activities. Both these points are mutually dependent.

Offshore World | 19 | December 2015 - January 2016

www.oswindia.com

INTERVIEW How do you evaluate the current India’s Offshore Drilling market for deep sea and sub-sea E&P activities? The current global Offshore Drilling market is challenging to say the least. The depression in International crude oil prices has deeply affected the Offshore Drilling market. While the present conditions are unfavourable for Drilling contractors, the market conditions will not remain the same forever. This definitely brings an opportunity to prepare when the market conditions turn in the favour of E&P activities. Only those companies which keep a bullish outlook towards the present market are going to prosper once the market conditions are up again. So, while it may seem like a bad phase, the current market definitely brings along opportunities for the long run. We are expecting stability in crude price from 2017 onwards. The main impact of declining prices has been on oil exporting countries since they cannot plan their drilling activities unless price of crude oil gets stable. The way the crude oil price is falling, no one wants to take chances. At the same time countries like India who are always behind the production can raise up their production. West Coast of India has already declined the production because of old growing oil fields and there is not much development happening on the East Coast. If Indian operators really want to develop their new fields, this is an excellent time for them to do the same as services are

mutually dependent. To flourish the drilling market, it is important that the E&P companies regularly remain updated with latest technology and the same be employed for such activities to make it as cost efficient as possible. For instance, ONGC mostly hires old rigs which in turn lead to increase in the risk of crew safety, increase in associated marine costs, slow production and less meterage. It is pertinent to mention that the drilling job involves high risk and thus safety becomes an important factor which must not be compromised. Safety and performance with new technology is much higher than that of old rigs. In your previous interview in the year 2012 with OSW, you had shared JDIL’s intent to expand the rig fleet and global footprint. What steps has JDIL taken towards the same over the last 3 years. And how has the drop in oil prices impacted the company’s plans? Talk about the presence of JDIL in other international markets. How do you compare providing services across various international markets vis-à-vis Indian market? In 2012, JDIL owned only two rigs. But over a span of the last 3 years we have expanded our rig fleet to five premium-class jack-up rigs and a

In terms of the Indian drilling business, the impact of decline in global crude price isn’t severe, but it depends on the willingness of operators to take advantage of this situation.

available at rock bottom prices. This way India can fulfil its growing demand of oil & gas and reduce the dependency on oil import. Your thoughts on the recent policy of switching from PSC to RSC formula and impact on oil field services providers. According to you what are the main drivers for the growth of drilling market in India? The recent policy of switching to Revenue sharing is going to be difficult for E&P companies to adapt to initially. However, the switch is most likely going to impact positively towards the E&P activities in India. This switch will benefit drilling market in India because it will ensure higher efficiency in the E&P activities. Within the RSC model, as the contractor keeps earning, the Government gets progressively higher revenue. This model will also ensure that companies become more likely to show interest in exploration. This especially holds significance as India has nearly two third of reserves being unexplored. It will also keep a check on the E&P companies from tampering with production of oil and gas. Moreover, controversies like that surrounding the KG-D6 block can be avoided with the RSC model. The main drivers for the growth of drilling market in India are investing in New Age Technology and Efficiency in E&P activities. Both these points are www.oswindia.com

drillship. The dropping oil price did not deter JDIL from its plans. This is evident from the fact that we recently purchased the rig ‘Rowan Louisiana’ to bid in one of the ONGC tenders and we won the contract for the same. JDIL is aggressively trying to expand into international markets like Egypt, Middle East, Indonesia, Malaysia, etc. Providing services in the International markets requires activities ranging from pre-qualification to opening a local office. It is a heavy task and it is important to go about it one step at a time. We are trying our best to enter into these markets, as we do have the technical capability to cater to the needs of the International market in addition to sticking to the highest level of service quality. What are your thoughts on the proposed marginal field policy and how are you aligning the business strategies to leverage on this opportunity in the near foreseeable future? The proposed marginal field policy is a big plus and we are definitely preparing to make full use of this opportunity. This policy will not only help India to augment domestic production of oil and gas but also give drilling contractors an incentive to step up to this opportunity. Our investment in premium class rigs and new technology will hopefully give us more leverage to make good use of this opportunity.

Offshore World | 20 | December 2015 - January 2016

INTERVIEW India is realigning the LNG strategies and gearing up for huge gas imports in the backdrop of decline in gas prices and the E&P activity is stagnated due to various challenges. How is this going to impact the oil field services providers industry on the whole and how are you gearing up for the future challenges? It’s a good strategy to secure the gas from international market but in today’s scenario price needs to be carefully check and negotiate but on the other hand, India has nearly two thirds of reserves being unexplored. The East Coast of India is having little E&P activities. It is already known that the East Coast has a huge reserve of oil and gas. In such a case, imports are going to turn out costly for the contractors and government alike. It is imperative that ONGC starts exploring new fields within the East Coast and deploy rigs to boost domestic production and cut down such huge import bills. In the end it depends on the willingness of operators to explore and develop new blocks and in turn raise production or otherwise keep spending on oil & gas imports which affects national interests. How, you think, the decline in global crude price and natural gas pricing formula in India has affected the Indian drilling business? What are the strategies JDIL adopted in protecting its bottom line in such scenario? The Indian drilling business has definitely taken a hit from the decline in global crude price. It is evident from the fact that demand in general is far lower than it was 12 to 18 months ago. However it is very important to note that since India isn’t an oil exporting country, India isn’t hit as badly as any of the oil exporting nations and hence it can use this opportunity to develop new fields and raise up exploration activities to lessen dependency from the import of oil & gas. Operators in India should take full advantage of this scenario and deploy more rigs to develop new fields and revive old growing fields. In terms of the Indian drilling business, the impact of decline in global crude price isn’t severe, but it depends on the willingness of operators to take advantage of this situation. JDIL is taking this opportunity to market our rigs in the International market. We already have three rigs deployed on long term contracts with ONGC and we were recently awarded another contract for our rig ‘Rowan Louisiana’ which we happened to purchase a few months back. So, in terms of protecting the bottom line, we are optimistic that JDIL will come out well in these times of depression in the market. As the inception of JDIL was for offshore drilling in India’s Oil & Gas sector, how have you realigned your strategies in changing global business environment? And what are your plans for the future (Do you intend to add FLNG and advanced technologies to fleet)? Yes, we have realigned our strategies to also consider international drilling market in addition to the local market. While for the most part we have been participating in the local market, it is time for JDIL to step into the International market and become a global brand. We are pursuing this with a lot of dedication and hopefully the results will show in the end.

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

Offshore World | 21 | December 2015 - January 2016

www.oswindia.com

FEATURES

HYDROGEN MANAGEMENT IN REFINERY COMPLEX Revamping existing refinery is vital in today’s scenario to produce fuels which meet stricter pollution norm as specified by regulators in the particular country/region, necessitate the addition of more hydrotreating facilities in the refinery complex or modify the existing ones so as to produce products like low sulphur gasoline and diesel that comply with the stipulated regulatory requirements. But revamp of existing refinery has its own challenges at each stage of the engineering cycle starting from conceptualisation to final erection/modification and commissioning of the revamped facilities and also keeping in mind the vast difference in capital costs and the payback period for recovering the costs in align with the crude oil price fluctuations and skewing refining margins. In such a scenario one of the aspects that become an important factor is the ‘Hydrogen Management’. Apart from hydrotreating requirements the H 2 requirement can further increase if the crude slate selected for a particular refinery is sour, i.e. high sulphur crude. The paper highlights the challenges faced by refiners to optimise the H 2 balance and suggest approaches to conduct a suitable hydrogen management so as to mitigate responses to such challenges.

evamp of existing refineries has become an important consideration to boost production or quality or both and thus enhance a refinery’s profitability and growth. In the current scenario the likelihood of any refiner adding new units or modifying existing ones is more as compared to them building a whole new grassroots refining complex. The major reason for this is the vast difference in capital costs and the payback period for recovering the costs due to vast crude oil price fluctuations and skewing refining margins. On the other hand revamp has its own challenges at each stage of the engineering cycle starting from conceptualisation to final erection/ modification and commissioning of the revamped facilities. One of the most common reasons for refineries undergoing revamps in today’s scenario is the need to produce fuels which meet stricter pollution norm as specified by regulators in the particular country/region. These essentially necessitate the addition of more hydrotreating facilities in the refinery complex or modify the existing ones so as to produce products like low sulphur gasoline and diesel that comply with the stipulated regulatory requirements. In such a scenario one of the aspects that become an important factor is the Hydrogen management. Apart from hydrotreating requirements the H2 requirement can further increase if the crude slate selected for a particular refinery is sour, i.e. high sulphur crude.

To produce H 2 of high purity to meet this hydrotreating demand coupled with uninterrupted supply of the same is a challenge that most refineries undergoing a turnaround, are facing. Insufficient H2 production for meeting the hydroprocessing requirements also poses as a bottleneck to the overall refinery throughput and operating margins. Excess H2 production, obviously, is a loss that a refiner shall not desire. A thorough hydrogen balance and hydrogen of high purity is required to boost the hydrotreating capacity and the catalyst life cycles. Improved H 2 management study along with improved sources of boosting the H2 production and its optimised usage are thus a very important aspect in the revamp study of the refineries. The intention of this paper is to mainly highlight the challenges faced by refiners to optimise the H2 balance and suggest approaches to conduct a suitable hydrogen management so as to mitigate responses to such challenges. A case study is also discussed to explain the options that can be considered in the H2 management exercise. Background The general categories in which the refineries requiring hydrogen for hydrotreating can be classified are: www.oswindia.com

a) Ones that depend on recovered hydrogen OR b) Ones that depend upon an on-purpose hydrogen plant The major consumers and generators of H2 in a typical refinery are shown in Figure 1. The schematic in Figure 1 illustrates how different purity H2 is fed to a unit more suited to receive a particular purity of H2. Also Table 1 highlights the typical average consumption of H2 and the purity of H2 required by the particular processing unit, as obtained from different refinery units’ data. In the configuration of the units, one important unit is the Catalytic Reforming Unit. Typically a Catalytic Reformer produces H2 in the purity range of 75-85%. The hydrogen thus produced is utilised in units like Naphtha Hydrotreater, Isomerisation units and some other units as shown in Figure 1. However not all of the hydrotreating units, for example Hydrocracker Unit, can be suited to utilise this H 2 since it may seriously reduce the catalyst activity especially during the EOR (End of Run) cycles of operation of the catalyst bed. Also the charge rates or the distillate yields can be drastically reduced. Typically there are times during a year where the product quality requirements, due to changing climatic conditions, need to be adjusted. Often this leads to different units adjusting to the available H2 pool by reducing the unit throughput so as to maintain the necessary H2/HC ratio and in turn the required catalyst activity. This reduced throughput in the hydroprocessing unit thereby cuts the profitability. Also after all the adjustments from the available intermediate storage pool are made, a continued problem like this may lead to reduced crude unit throughput as well. It is needless to mention again that this will definitely impact the refiner’s profit. Combination of these problems along with a scenario where some of the more complex refineries which also have units like Hydrocracker, Gas oil hydrotreaters or Diesel hydrotreaters in the configuration need to add the on-purpose H2 plant so as to ensure H2 availability for the unit operation. Another important factor to be considered is to record the efficiency of the on-purpose H2 Unit (such as SMR-Steam Methane Reforming Unit) and establish the costs of running the unit against profits made from the running of the hydroprocessing units. While the purity of H2 produced from both the types is different the suggested method would be to have a combination of the two methods discussed above. This shall help to optimise the usage of recovered H2 and at the same time reduce production from an on-purpose hydrogen plant thereby saving on the costs incurred for producing such

Offshore World | 22 | December 2015 - January 2016

FEATURES

Figure 1: Schematic diagram indicating major hydrogen generators and consumers in a typical refining complex.

hydrogen due to the utilisation of steam and fuels such as Natural gas, LPG or Naphtha in the on-purpose H2 producing unit. Technical Considerations The refinery hydrogen management should include some of the following considerations based on the configuration of units that it has, so as to address the aspect in a systematic manner:

designed for. Also there was an additional Hydrogen Manufacturing Unit (HMU) which used NG and Steam as fuels and operated at a capacity of about 60-80% of its design capacity depending on the feedstock handled in various downstream user units such as VGO-Hydrotreater, Diesel Hydrotreater (DHDT) etc. This HMU produced hydrogen of purity ~99.9% vol. The network study thus led to the next two steps of analysis:

1) Configure the downstream units so as to ensure maximum H 2 recovery from the processes itself.

2) Maximise the reuse of recovered H2 by diverting it to users that are more suited to utilise the purity of H2 recovered.

Network analysis is the first thing that the refining team and the engineering team need to get on to.

Table 1: Hydrotreating Units H 2 requirement with purity range

A case study is discussed below in order to explain this point. Case Study: In one of the refineryâ&#x20AC;&#x2122;s that is planning to undergo a major upgradation and revamp work, the network analysis was done to establish if there is any excess H2 production that is lying unused and is being wasted by flaring. The study hovered on the existing CCR unit which produced the H2 of purity ~90% vol. The original design and H2 balance had yielded no excess H2. However, on an average about 30 KNm3/h of H2 produced from the unit was wasted in flare the reason being that the user i.e. Naphtha Hydrotreater (NHT) was using a different feedstock Naphtha than what it was originally

Unit Name

H 2 required (wt% of Unit Feed)

Typical H 2 purity required

Hydrocracker

~1.9

>98%

Diesel-HT (DHDT)

~0.95

>90%

Vacuum Gas O il-HT ~2.0 (VGO-HT)

>90%

Naphtha-HT (NHT)

~0.43

~85-90%

FCC Gasoline-HT

~0.42

~85-90%

Kerosene-HT (KHT)

~0.44

~85-90%

Offshore World | 23 | December 2015 - January 2016

www.oswindia.com

FEATURES

Figure 2: Hydrogen production technologies

Various options were considered to utilise the CCR produced H2 so as to avoid flaring the same. The options that were considered and the challenges that were faced are discussed below, briefly: Purity of CCR produced hydrogen was less and it would lower the H2 rich header (99.9% purity) purity and impact users like GOHT and DHDT. The impact would be mainly on the catalyst activity of the reactor beds of the units concerned especially during the End of Run (EOR) cycles where the H2/HC ratio would decline appreciably to a less acceptable level and accelerate the catalyst poisoning. It was thus decided to consider injection of H2 into the Hydrogen header while continuously monitoring the H2/HC ratio so as to not let it fall below the design minimum. Thus only a certain amount of H2 could be effectively used under this option. Another option was to consider diverting the H2 to Refinery Fuel Gas (RFG) header. The RFG consisted of H2 in the range of ~43% (avg) and maximum content was witnessed in the range of ~50% vol to 60% vol due to seasonal changes during a short period of time each year. This presented with an opportunity of mixing the CCR generated H2 in the RFG header such that the maximum content of 60% vol. H2 is not exceeded in the RFG composition. It was established that no burner modification would be required for any of the Fuel Gas (FG) fired heaters since they already were used to trouble free operation when the H2 composition in FG was within the limit of 60% vol. maximum. Any increase in the H2 levels in FG beyond this limit had the potential to affect the flame stability and patterns as was established by past operating experience. To be on the safer side it was decided to limit the infusion of the H2 in RFG header such that the H2 component was limited to 50% vol. maximum. www.oswindia.com

It was also established that the result of infusing the excess H2 thus produced from CCR, towards the two options as listed above would also make the HMU operate at its turndown capacity i.e. 50% of design capacity. However an upgradation of the refinery which was in the pipeline would help in utilising the HMU capacity to the fullest by addition of more new hydroprocessing units in the configuration. The result of the study performed on the options discussed above yielded the following implementable options: The combination of infusing the excess H2 produced by CCR in the H2 rich header and the RFG header at the same time was the most viable option since it had minimum impact on the operational flexibility, future revamp plans and minimum modification to existing unit equipments and infrastructure. The selected option thus was helpful in reducing the flaring of excess H2 by about 70%. 3) Consider enhancing the purity of recovered hydrogen by deploying PSA or similar purification technology instead of going for an on-purpose hydrogen plant. Purity of hydrogen is also an important factor to ensure continued operation of the hydroprocessing units. An on-purpose H2 plant like the Steam methane reformer which uses naphtha, LPG or natural gas as feed can produce H2 to the purity of 99.9% by deploying PSA units in the purification cycle of the process. They also ensure the availability of the H2 for continued levels of design throughput processing of these units. Even for the case that is discussed above one of the aspects that could have been considered was the installation of a PSA unit for the H2 produced from CCR so

Offshore World | 24 | December 2015 - January 2016

FEATURES as to improve its purity and thus utilise it fully in the hydro treating units. The routing options of H2 generated from CCR are depicted in figure 1 as well. The H2 can either be routed to units suited to utilising the purity of H2 that is generated or/and it can be routed to PSA (H2 purification) unit for enhancing the purity. 4) Reduce the requirement of additional hydrogen generation facility so as to cut down on the costs of steam, natural gas, LPG or naphtha required for production of hydrogen from the same. As can be seen in the discussion of the case study in point 1 through 3 it is realised that a proper configuration shall definitely help in deciding on the optimum HMU capacity to be configured and thereby reduce the costs significantly by reducing the use of the fuels required for production of H2 from the same. 5) Evaluate the number of on-stream days of the on-purpose H2 plant. When undergoing revamp this shall be a major consideration since it can easily impact cost and lead to extreme operating problems such as either under utilisation or insufficient H2 pool of the desired purity for running the hydro treating units that were added as a part of the revamp. Also the number of on-stream days from historical operation data shall help in evaluating future HMU technologies that can be selected to be a part of the refinery configuration. PSA based processes are more preferred in refineries built post 1980 since they offer higher purity of H2 in addition to being efficient due to more efficient reformer designs and additional export of steam. Figure 2 shows the difference between a conventional method (medium purity of H2 ~94-97%) of H2 production to the PSA based process. For running an on-purpose H2 generation unit there can be other hurdles also, such as the availability of the feedstock like Natural Gas for the HMU. This may be due to many economic and geo-political reasons there-by impacting the unitâ&#x20AC;&#x2122;s run time. 6) Evaluate the shutdown plans for the different hydroprocessing units and schedule them so as to best utilise the available H2 pool. Other than the major turnaround of the entire refinery the other refinery shutdown cases shall be evaluated in detail. If only the worst case is considered as a safe design option then it can lead to overdesign of the H2 facility in a refinery complex. The mostly likely cases of occurrence shall be discussed and evaluated thoroughly. This shall help in utilising the available H2 pool in an optimum manner and thus help in deciding if at all any additional H2 manufacturing capacity is actually required to deal with different shutdown cases.

which can be utilised for units like NHT, Isomerisation and DHDS and thus help in having flexibility to run these units without fully relying on the H2 manufacturing facility. Else there can be a situation where the H2 capacity shall be in excess just to meet the unit start-up requirements and shall remain under utilised during the normal run of the units. Such situations can be avoided by taking into considerations examples like the ones discussed here. 9) Establish the crude basket to be used and evaluate the daily changes in the crude slate used i.e. sweet or sour crude. Selection of the feedstock shall be a determining aspect as well for configuration of the H2 balance of the refinery. The H2 requirement can further increase if the crude slate selected for a particular refinery is sour, i.e. high sulphur crude. While it is difficult to firm up completely on a particular crude slate to be utilised for the full run length of a refinery in an ever evolving energy market, emphasis should be put on deciding on the most possible crude slates that shall be utilised for the refinery operation. This shall be then utilised in carrying out detailed studies like the LP Modeling configuration which shall help in evaluating and configuring an optimum H2 requirement for the refinery and for the different selected crude slates. The future revamps shall also be carried out keeping this aspect in mind and benchmarking the H2 utilisation due to any change in feedstock so as to best enable the revamp planners to decide on the most optimum H2 balance for the refinery to be revamped. Conclusion The refinery revamp configuration study typically takes into account the geographical aspects, environmental laws of the land and socio-economic considerations for deciding on the refinery configuration. However as has been outlined by means of a case study and the technical considerations in this paper, the importance of configuring an optimum H 2 facility for assisting the requirements of such a refinery, can no less be undermined. The cost savings arising due to an efficient H2 balance study are immense in both the capital and operating expenditure stages of such projects. And the solution to such efficient H2 management does not lie in pointing and picking any one particular aspect. It in fact is a combination of various technical considerations as discussed in this paper that shall help a refiner in evaluating the best possible H2 facility for the configuration of a cost friendly and economically viable project. (The conclusions presented in this article are solely those of the author/s, and cannot be ascribed to Fluor Corporation and/or any of its subsidiaries.)

7) Study the summer versus winter product quality requirements. The impact of season as also specifically pointed out in the case study in points 1 through 3 are helpful in establishing the operational impact of changes on the equipments concerned. The impact of seasonal changes on the units helps in realising the operational minima and maxima that can be attained without impacting the unit run. This in turn shall help in deciding on how efficiently the various utility and auxiliary systems can be utilised, H2 being one of them. 8) Optimise the storage facilities so as to have the desired unit start-up sequence. The design of the intermediate product storage facilities is a key aspect that shall help in deciding on the optimum H2 manufacturing capacity. As for example, if for a refinery the CCR feed tank capacity is sufficiently sized then it shall help in generation of the H2

Amit D Choudhary Process Design Engineer Fluor Daniel India Pvt Ltd Email: amit.d.choudhary@fluor.com Srinivasa Oruganti Department Manager - Process Fluor Daniel India Pvt Ltd Email: srinivasa.oruganti@fluor.com

Offshore World | 25 | December 2015 - January 2016

www.oswindia.com

INTERVIEW

‘H-Energy is aiming to create a competitionbased natural gas market in India’

H-Energy, a subsidiary of the real estate giant Hiranandani Group, was incepted on the pursuit of providing the nation an environmentally sound, world-class infrastructure and utility solutions of energy, says Darshan Hiranandani, Manging Director, H-Energy. In a candid interaction with Mittravinda Ranjan and Rakesh Roy, the young Entrepreneur details on the company’s businesses in India and its future plans. Excerpts:

H-Energy’s FSRU project and proposed gas pipeline infrastructure in the Eastern India at Digha, West Bengal will promote rapid ‘Economic Growth’ in Eastern states like West Bengal and Odisha.

www.oswindia.com

Offshore World | 26 | December 2015 - January 2016

INTERVIEW As Hirananadani Group is known as the Real Estate giant in the country, what was the objective of venturing into LNG and Gas Marketing business; and how do you evaluate the current and future outlook of Natural Gas market of India? As we know that the energy need of the country has been grown up year on year, the quest to provide the nation an environmentally sound, worldclass infrastructure and utility solutions of energy led to the inception of H-Energy. Furthermore, we realised that monopoly of state-owned natural gas processing and distribution companies like GAIL has downgraded the natural gas market in India, thus the customers aren’t getting the real benefits. Inception of H-Energy was the pursuit of bringing more gas into the country. Natural gas, which is considered as a clean energy, share in Indian energy mix is nominal as comparison to the World energy mix. As like its

approved by PNGRB and are expected to ready and synchronised by the completion of the Jaigarh terminal by 2019. Can you elaborate more into the business model of Jaigarh LNG Terminal as it has said that it will be a build own & operate (BOO) model where H-Energy will basically provide the infrastructure to the interesting party who want to get LNG from overseas? The options will be both. H-Energy’s Jaigarh LNG Terminal will provide its infrastructure to third party users for regasification of LNG to end users of gas such as: power & fertiliser plants, oil refineries, steel plants, etc. The terminal will also give a platform to gas marketing companies for independently sourcing LNG from international markets. For example; H-Energy has signed agreements with Indian end-user companies of natural gas for providing cheaper Shale gas from USA and also taking off liquefaction capacity of the USA simultaneously.

H-Energy’s Jaigarh LNG Terminal will provide its infrastructure to third party users for regasification of LNG and will also give a platform to gas marketing companies for independently sourcing LNG from international markets.

Asian counterpart - China, India has also been funded and depend more into coal-based power for its growing energy needs. So gas can be played a key role as a clean fuel for the country’s energy needs and feedstocks for end-user industries of gas like; power & fertiliser plants and refineries. Other user industries like steel plant, glass plant, etc also require gas. CNG and City gas requirement in the country will be continued to grow. H-Energy is aiming to create a competition-based natural gas market in India which will further bring down the pricing of gas as similar happened to the Indian telecom industry. Please apprise us the H-Energy business in India in detail? H-Energy is currently setting up two LNG projects in India – one is in the west coast at Jaigarh port in Ratnagiri, Maharashtra, which will be a 8 MTPA LNG import, storage and regasification terminal; and other is in the east coast where we plan to set up an offshore floating storage facility near Digha coast in West Bengal of 6 MMTPA capacity with an intent to supply natural gas to the eastern and northern states of India. H-Energy is also working on two long cross-country pipelines – one is Jaigarh to Dabhol of 60 km long pipeline; and other is from Jaigarh to Mangalore, which is 635 km long pipeline which aims to cater the natural gas market of Mangalore and Bengaluru. Both the pipelines have been

The idea is to keep the interest of Indian customers and giving them cheaper natural gas and deliver it direct to their doorstep. Please thru more lights on H-Energy’s plan to foray into Eastern India in offshore LNG operations? H-Energy’s FSRU project and proposed gas pipeline infrastructure in the Eastern India at Digha, West Bengal will promote rapid ‘Economic Growth’ in Eastern states like West Bengal and Odisha. H-Energy strategic plan is to connect with a gas grid in between states like Bihar, Jharkhand, West Bengal and Odisha. H-Energy is also exploring the feasibility of supplying Natural Gas to North Bengal through the pipeline network of Bangladesh with minimal capital investment. All major techno-economic studies for the project have already been completed and commissioning of the project is planned in Q4, 2018. The project life is 25 years, with an estimated expenditure of ` 2,400 crore on the FSRU and ` 2,700 crore on the total gas pipeline system, both sub-sea and onshore components put together. Can you apprise us the long term future plans of H-Energy in India? For the time being, we are focused on commissioning of these projects.

Offshore World | 27 | December 2015 - January 2016

www.oswindia.com

FEATURES

APPRAISAL OF CORROSION PREVENTION AND CONTROL MEASURES BY CORROSION AUDIT Pipelines are the most efficient means of transportation in upstream oil and gas industry – onshore and offshore – to carry and deliver large volumes of crude oil and gas within oil and gas fields to refineries and refined products to large consumption or storage stations. The material of construction of these pipelines is generally carbon steel. The safe transmission of hydrocarbons is sometimes jeopardised when pipelines fail due to any of the reasons including – external and internal corrosion, third party damage, defective material or seam weld or girth weld, construction damage etc. Thus ‘Efficient Corrosion Management’ plays an important role in enhancing life of pipeline assets of an enterprise. Today’s requirement is to deviate away from ‘Find it, Fix it’ mentality to the proactive corrosion control strategies. Corrosion Audit is one of the tools used for effective management of corrosion prevention and control measure. This article provides details of corrosion audit methodology which has been successfully used in Western Offshore in India.

ipelines are among the most efficient means of transportation. They carry and deliver large quantities of fluids from source to user by continuously flowing the material. It is also the only feasible mode of transporting large volumes of crude oil and gas within oil and gas fields, to refineries and refined products to large consumption or storage stations. The material of construction of these pipelines is generally carbon steel. The safe transmission of hydrocarbons is sometimes jeopardised when pipelines fail due to any of the reasons including – external and internal corrosion, third party damage, defective material or seam weld or girth weld, construction damage etc. Years ago, a major portion of transmission lines as well as oil field pipelines were traversing uninhabited areas. The cities have grown and now some of these pipelines are close to or are within inhabited areas. This increases risk due to failure of the pipelines carrying hazardous fluids. In upstream oil and gas industry, the activity is broadly divided in to two areas – onshore and offshore. In onshore oil and gas fields, the pipelines carry oil and gas from different wells to the nearby gathering station, also called Group Gathering Station (GGS). These are multiphase pipelines and may also carry water and are vulnerable to internal corrosion. After processing at the GGS, the fluids may be transported to another central facility or directly to refinery. The latter category of pipelines is relatively less susceptible to internal corrosion. In offshore, oil and gas wells are located at remote placed and subsea. The fluids produced from several wells are usually combined at well head platform and transported through a single, large-diameter pipeline as multiphase fluids to processing platform, where oil, gas and water are separated. Sometimes unprocessed multiphase fluids are transported to onshore for further separation of the phases.

The pipelines carrying unprocessed fluids from oil and gas wells to processing station, whether onshore or offshore are called well fluid pipelines. They carry water along with hydrocarbons. In addition to hydrocarbons, the non-hydrocarbon gases such as CO 2 and H 2 S are also produced from many reservoirs. They create corrosive environment for internal surface of the pipeline. Additionally, the presence of H 2 S can promote suplhide stress www.oswindia.com

corrosion cracking. Anaerobic Sulphate Reducing Bacteria (SRB) are additional threat to pipeline as they cause Microbiologically Influenced Corrosion (MIC). This form of corrosion is especially more prevalent in the fields where water is injected in reservoir to improve crude oil recovery [1,2] . Water injection is one of the methods for maximising oil production and improving oil recovery from oil fields. It entails injection of water in sufficient quantities with acceptable quality into the appropriate zones of the reservoir in a cost efficient manner. Treated water is transmitted after treatment to injection well through carbon steel pipelines. Corrosion is manifested in these pipelines through two mechanisms – oxygen corrosion and MIC [1] . As the reservoir producing oil deplete, proportion of water in the produced fluids increases. This aggregates corrosion problem in well fluid pipelines. In such an event, the probability of their failure due to internal corrosion will increase. In offshore, maintenance of such pipelines and repair upon failure is laborious as well expensive. Efficient corrosion management plays an important role in enhancing life of pipeline assets of an enterprise. Today’s requirement is to deviate away from ‘Find it, Fix it’ mentality to the proactive corrosion control strategies. Corrosion Audit is one of the tools used for effective management of corrosion prevention and control measure. This article provides details of corrosion audit methodology which has been successfully used in Western Offshore in India. The prevention of corrosion does require attention throughout the life cycle of the pipeline, from design through fabrication and commissioning, to operation. Once corrosion process is established, it becomes increasingly difficult to mitigate their effect on pipeline integrity. Over the life, changes in flow and fluid composition modify the corrosion processes. In offshore, pipelines invariably fail due to internal corrosion. The factors that affect internal corrosion of oil and gas pipelines are [1,2] : • Aqueous phase composition, especially salinity, volatile fatty acid

Offshore World | 28 | December 2015 - January 2016

FEATURES

•

• •

•

concentration and buffer ion concentration, such as bicarbonate. High chloride concentration tends to increase localised pitting corrosion, an increase in concentration of volatile fatty acids enhances corrosion rate and presence of bicarbonate lowers severity of corrosion rate by raising system pH. pH: Corrosion rates are lower at higher pH and vice versa. The presence of acidic gases such as carbon dioxide and hydrogen sulphide lowers pH of the system. The concentration of these gases influences solubility in water and hence the corrosion rate. Corrosion causing gases, such as carbon dioxide and hydrogen sulphide that accompany hydrocarbons produced from reservoir and oxygen which is present in injection water. Microbiologically Influenced Corrosion caused by sulphate reducing bacteria or acid producing bacteria. Temperature: Oxygen corrosion rate increases with rise in temperature. The temperature behaviour of carbon dioxide and hydrogen sulphide corrosion is dependent upon nature of corrosion product film formed at a particular temperature. Pressure: The solubility of gas in water increases with rise in system pressure, along with concentration of gas. Higher solubility of acidic gases lowers pH and increases corrosion rate. Generally, the influence of gas on corrosion severity is expressed partial pressure of gas. Fluid flow velocity and flow regime, in case of multiphase flow. Segregated flow pattern, in which case oil, gas and water phases are separated and water phase forms the bottom most layer, is the worst case from corrosion view point. Extent of water present with produced hydrocarbons. As proportion of water produced along with hydrocarbons increases, the chances of its segregation and corrosion increase. Nature of crude oil, e.g. wettability and emulsification behaviour. The nature of crude oil also influences tendency of water segregation. Polar components, asphaltenes and resins, present in crude oil tend to emulsify water.

Figure 2: Failed water injection pipeline. Water flowing through the pipeline was desired to be oxygen free, but was carrying oxygen on several occasions.

A few examples of failures of subsea pipelines are shown in Figures 1 to 3.

Figure 3: Pipeline failure due to internal corrosion. The failure was assigned to segregated flow, presence of SRB and carbon dioxide.

Figure 1: Section of pipeline carrying multiphase fluids, failed due to internal corrosion. Flow pattern was segregates, gas phase had carbon dioxide.

Corrosion Management It is always desirable to keep pipelines in good health. The pipelines are protected against external corrosion by coating and cathodic protection. The most commonly used coating in Indian Offshore is coal tar enamel and sacrificial anodes are used to provide cathodic protection. Internal corrosion is the most common causative reason for failure of the subsea pipelines. Application of corrosion inhibitor, biocide and pigging are the frequently used practices for internal corrosion control. Processing of fluids, such as removal of oxygen from injection water, demuslfication of crude oil to remove water for

Offshore World | 29 | December 2015 - January 2016

www.oswindia.com

FEATURES transportation of this oil through trunk pipelines and dehydration of gas by removal of water before transporting through trunk pipelines are also carried to minimise the vulnerability of these pipelines towards internal corrosion. Corrosion monitoring techniques, such as iron count, weight loss coupons, Electrical Resistance (ER) probe and Linear Polarisation Probe (LPR) are used to evaluate the effectiveness of control measures [1,2] . As a part of corrosion management, it is always desirable to examine whether the desired corrosion control measures are in place or not and whether any improvement in necessitated. Corrosion Audit is adopted for this purpose. This paper describes corrosion audit and its methodology at length, along with a case study. What is Corrosion Audit? Corrosion audit of pipelines is carried out with the objective to assess the vulnerability of pipelines towards corrosion, adequacy of existing corrosion monitoring and mitigation practices and to recommend preventive/remedial measures for corrosion control. Corrosion audit is a tool: • To identify various factors responsible for corrosion of all the well fluid, water injection, gas lift and collector pipelines. • To assess the vulnerability of pipelines towards corrosion. • To assess adequacy of existing corrosion control and monitoring practices that are in place for a pipeline network. • To study the regions of H 2S environment severity for various pipelines w.r.t. sulphide stress corrosion cracking (SSC) of carbon and low alloy steel. • To augment efforts for corrosion monitoring and control. It is a predictive maintenance technique and involves very little expenditure. It helps to plan and execute corrective measures in advance so that breakdown and consequent losses can be avoided. Corrosion Audit should not be misunderstood as giving information on risk associated with pipeline failure. Audit helps to: • Understand the real picture of corrosion control measures in practice • Bring out lapses and flaws, if any, in the system • Strengthen weaknesses, if any, in the system • Have a feel of level of vulnerability of pipelines to leaks Further Audits pertaining to ISO 9001 Quality Management System cannot replace Corrosion Audit. The former are aimed at quality management and do not need subject matter expert whereas latter needs expertise in corrosion, oil and gas production process and industry as a whole. Methodology Adopted for Corrosion Audit It begins with review of: • Design parameters • Operating parameters • Inspection and monitoring records • Failure history • Repairs and maintenance records • Fluid/gas parameters and quality • Fluid flow pattern and velocity www.oswindia.com

The degree of corrosivity of the produced water is also examined in the laboratory by carrying out corrosion rate estimation study in under simulated conditions of pressure, temperature, composition of corrosive gases in High Pressure High Temperature Autoclave. The produced water flowing through the pipeline, along with hydrocarbons, is used as aqueous medium for these corrosion rate studies. The study also included – failure analysis of leaked lines, chemical analysis and microbiological analysis (for enumeration of Sulphate Reducing Bacteria) of produced water, assessment of vulnerability towards SSCC, corrosion rate prediction by software. The work further involves review of present practices vis-à-vis: • International standards and codes • International practices • New technologies / tools The final Corrosion Audit report includes: • Correlation among various parameters • Assessment of vulnerability of pipelines towards corrosion • Prioritisation of pipelines according to risk of corrosion. • Recommendations to minimise vulnerability of pipelines to corrosion • Recommendations to control process parameters • Recommendations on implementation of new technologies Corrosion Audit Case Study A case study of Corrosion Audit of Well Fluid Pipelines is presented here to elaborate upon the different steps involved in the process of corrosion audit. The design and operating data pertaining to 20 well fluid lines (WFL), was scrutinised. A majority of these lines (11 in number) are older than 16 years or more and others are 7-9 years old. Water content of the fluid flowing in these lines varies from 30 – 70% and CO 2 in the gas varies from 2 – 3 mole %. Design temperature and pressure of the lines were 93oC and ~2000 – 2100 psi respectively. The records of pipelines were traced to look for any leaks in the past. One of the lines had leaked first time in about four years, and subsequently developed 17 leaks. The line was finally replaced after 11 years of service. No leak has occurred in this new line after about seven years of service since commissioning. A detailed analysis of the failed line was carried out to establish the causes of failure. The factors were established as responsible for this failure as: • Water content, which was only 7% after two years of service of this line, ranged between 21 to 40% during the subsequent years till first leak was observed • Presence of CO 2 (2.62 mole %) • Presence of sulphate reducing bacteria (SRB) • Segregated flow pattern Audit of Corrosion Monitoring Measures: The corrosion rate monitoring of the lines gives an indication about dynamics of health of the pipelines and efficacy of corrosion mitigation method that are adopted. The most common corrosion monitoring techniques that are adopted in multiphase well fluid lines are: 1) Iron count 2) Weight loss coupons

Offshore World | 30 | December 2015 - January 2016

FEATURES 3) ER probes 4) LPR probes, in case of very high water content 5) Count of Sulphate Reducing Bacteria (SRB) for microbiologically induced corrosion The only corrosion monitoring technique operational for these well fluid lines was iron count and SRB count measurement. Iron count should be taken only as an indicative tool. In this case, corrosion monitoring must be supplemented by other techniques such as weight loss coupons, ER probes and LPR probes. SRB are the most destructive group of bacteria causing Microbiologically Induced Corrosion (MIC). SRB are a group of anaerobic bacteria that generate hydrogen sulfide (H 2S). f can cause a number of significant problems in water. These problems range from blackening of equipment, iron sulphide formation (black solids), slime formations, and extensive corrosion. The SRB form a part of a microbial community (referred to sometimes as a ‘consortium’). Within these consortia, the SRB are able to function deep within the biofilms. Generally, the biofilms are formed within tubercles, encrustations, and slimes. Since the SRB are deeper down in these growths, they may not be recovered in water samples taken from the flow over the growths. But still the most common and primary method of detection of SRB is from water samples. The planktonic SRB are enumerated by serial dilution or rapid detection kit. Quantitative SRB estimation as per NACE Test Method TM 0212 has been carried out and data pertaining to these results was collected for scrutiny [3] . As per this data, SRB count has regularly been of the order of 10 3 per ml in lines WFL-8, WFL-13, WFL-16 and WFL-17. The data also showed that the lines WFL -2, WFL-6 and WFL-14 are free from SRB. In other lines, SRB have been detected on intermittent occasions. It was inferred from the SRB monitoring data that some of the lines are infected by these bacteria and are prone to MIC. Audit of Corrosion Mitigation Measures: The following corrosion mitigation measures are generally adopted for multiphase pipeline: 1) Corrosion inhibitor injection – continuous/batch/combined mode 2) Application of bactericide 3) Pigging of the lines The available records available showed that batch corrosion inhibitor treatment was given about a year before the audit. Since then no chemical treatment was given. The chemical treatment was aimed at cleaning the lines with inhibited acid, followed by dosing with biocide and then coating of the internal surface of the line with corrosion inhibitor. The same volume of corrosion inhibitor and biocide was dosed, irrespective of the line size and length. Moreover, when the lines are carrying high percentage of water with crude oil, the frequency of dosing is utterly inadequate. Corrosion inhibitors remain the primary corrosion control option for treating produced oil and gas. They provide a cost effective and flexible solution to inhibiting the corrosion of carbon and low alloy steels whose selective use is critical to the economic viability of field development. However, the casual use of a corrosion inhibitor can create a false sense of security. The frequency of biocide dosing is also inadequate in the light of the results of monitoring data that almost all the lines have shown presence of SRB, with

preponderance in some of the lines. As per general experience, if bacterial count is ≤10 2 per ml, the problem is not serious and needs monitoring. If bacterial count is ≥10 4 per ml, the problem is serious and needs regular treatment. As per these general guidelines, most of these well fluid lines fall in the category of significant to serious MIC problem and need regular monitoring and treatment. Pigging is the most widely accepted method of cleaning pipelines, which have bacterial growth and in which segregated water gets accumulated. The following points were audited on the pigging issue: 1) The pigging frequency each line 2) Whether the fixed frequency is practiced 3) Whether adequate pigging frequency exists for each line 4) The condition of pigs received after pigging 5) Whether the muck received from pigging is analysed 6) Results of chemical / microbiological analysis of muck The pigging of these lines is normally carried out using scrapper pigs, with or without brushes, having metallic body and PU cups. The past one year record showed that the preset frequency was generally adhered to. But the pigging frequency for these lines is randomly distributed as quarterly, half yearly and annual. The logic for this random distribution was not clear as the lines with same flow rate and with the same water cut were having half yearly as well as quarterly pigging frequency. For example, the fluids flowing through the lines WFL – 16, WFL – 5 and WFL – 20 have the same water content (~75%), but they are pigged quarterly, half yearly and annually. The pigs were received in good condition in all the cases, except the three lines, WFL – 12, WFL – 5 and WFL – 17. The damaged pig cannot perform full function. Therefore, corrective measures are required for those lines from which damaged pig was received. The lines WFL – 3, WFL – 14 and WFL – 20 do not have pig receiver at process end and therefore these lines are not pigged. The stagnation of water, MIC and CO 2 corrosion have been found to be dominant causes of internal corrosion resulting into leakage of lines. In the absence of pigging the probability of corrosion related failures increases. Only scant data was available about analysis of muck received after pigging, which is reported to be wax. In order to have a comprehensive study of the effect and efficacy of pigging, monitoring of following parameters before and after pigging can give additional information about the health of pipelines: • H 2 S content of the gas • SRB and Acid Producing Bacteria (APB) count If H 2 S content is higher before pigging than after pigging, it indicates active sessile bacteria in the pipeline. Such a pipeline will need pigging with wire brush so that slimy film on the surface of the bacterial colonies is disrupted. This should be followed by slug dose of biocide. Microbiological analysis of the muck received during pigging is helpful in assessment of the development of colonies inside the pipe. A high SRB count (ca more than 10 4 ) in solids scrapped from corroded surfaces is an indication of significant bacterial attack. Counts above 10 5 are common only in severely attacked system. Flow Pattern Analysis: Well fluid lines carry gas, oil and water. Under these multiphase flow conditions, various flow regimes or flow patterns are

Offshore World | 31 | December 2015 - January 2016

www.oswindia.com

FEATURES possible, depending upon flow rates and physical properties of the individual phases, the pipeline diameter, pressure loss along the length of the pipeline, fluid heat transfer properties and pipeline inclination. The flow patterns were determined for all the pipelines by using PIPESOFT software. This software defines three types of flow patterns – Segregated, Intermittent and Transient. Stratified flow pattern occurs at relatively low gas and liquid flow rates. The two phases are separated by gravity, where liquid phase flows at the bottom of the pipe and gas phase at the top. Intermittent Flow is characterised by alternate flow of liquid and gas. Plugs or slugs of liquid, which fill the entire pipe cross sectional area, are separated by gas pockets, which contain a stratified liquid layer flowing along the bottom of the pipe. The mechanism of the flow is that of a fast moving liquid slug overriding the slow moving liquid film ahead of it. In transient flow pattern, the flow pattern alters along the pipeline length, in part due to pipeline topography. The flow pattern in different lines have been found to vary as described in Table 1. Table 1: Flow Pattern in Well Fluid Lines Flow Pattern Segregated

Pipelines WFL – 1, WFL – 6, WFL -8, WFL – 10, WFL – 12, WFL – 17, WFL – 18, WFL – 19 and WFL – 20

Intermittent

WFL – 2, WFL - 4, WFL – 5, WFL – 7, WFL – 9, WFL – 14, WFL – 16

Transient

WFL – 3, WFL – 11, WFL - 13, WFL – 15

The segregated flow pattern has been computed to be present in 9 out of 20 pipelines whereas 7 lines have intermittent and 4 lines have transient flow pattern. The nine pipelines with segregated flow pattern are more prone to failure as compared to the remaining 11 pipelines, which have intermittent and transient flow pattern. Corrosion Rate Analysis by Software: Corrosivity of the fluids flowing through the well fluid pipelines towards carbon steel, i.e. the material construction of the pipelines was determined with the help of NORSOK M506 software [4] . This software gives an assessment of corrosion rate due to the presence of CO 2 and water. An average value of 2 mole% of CO 2 was used for all the pipelines. The uniform corrosion was found to vary from 7.2 mpy to 16.8 mpy. As per design data, there is corrosion allowance of 3 mm, considering 5 mpy uniform corrosion rate and 25 year service life. Thus, these corrosion rates are much higher than the design values. Further, the pitting corrosion rates are generally estimated as 2.5 times the uniform corrosion rate. Since the failures are most frequently due to localised corrosion, therefore, the higher corrosion rates due to pitting corrosion (which upon calculation are in the range of 18 to 42 mpy) are more relevant in the context of pipeline integrity maintenance. The corrosion rates for all the pipelines are on higher side, with highest severity in the pipelines WFL – 2, WFL – 3 and WFL – 10 having uniform corrosion rates of 14.8, 15.2 and 16.8 mpy respectively. Assessment of Vulnerability of Pipelines to Sulphide Stress Corrosion Cracking (SSCC): H 2 S ppm varies in these pipelines from 10 (WFL – 10) to 65 ppm (WFL – 4) and partial pressure of H 2S varies from 0.002 to 0.0111 respectively. Under the conditions currently prevailing in the pipelines and the guidelines described in MR 0175 / ISO 15156 [5], none of the pipelines, whether oil or gas, is vulnerable to SSCC. www.oswindia.com

Failure Risk Assessment: The various factors that affect severity of corrosion in multiphase pipelines can be delineated as: 1) General corrosion due to high water cut, CO 2 and H 2S in the system 2) Localised corrosion due to: a. CO 2 and H 2S b. SRB c. Segregated flow pattern The main risk of pipeline failure, in this case, is due to high water cut, CO 2 corrosion, SRB and segregated flow pattern. In this case, H 2S levels are not alarming and will not be a threat. Failure of a line will depend upon the present level of severity of corrosion as well as the age of the pipeline because this will account for metal loss due to corrosion in the past. On the basis of these factors a semi-quantitative model is derived (Table 2) for prioritising failure risk of these pipelines. Under this semi-quantitative model, a rating of 0 to 10 is given to all the factors which contribute of corrosion of pipelines. The value 10 stands for highest probability of leak due to the contribution of that particular factor. A value of 50 depicts highest and a value of 16 depicts least vulnerability. On the basis of weightage given to various gross factors that can lead to failure of a pipeline, the failure vulnerability rating of all the pipelines was calculated and is given in Table 3. As per this rating, five pipelines, viz. WFL-8, WFL-17, WFL-18, WFL-19 and WFL-20 are the most vulnerable, with weightage points more than 45. There is only one line with low vulnerability, with weightage 32 and remaining fourteen pipelines have intermediate vulnerability (weightage points 26 – 45). These weightage points are assigned to the pipelines assuming that there are no protective measures being adopted against internal corrosion. If internal Table 2: Semi-quantitative Model for Prioritising Risk of Pipeline Failure Sl. No. 1.

Factor Age of the Pipeline

Corrosion Rate

Flow Pattern

SRB

Weightage < 5 years

5 – <10 years

10 - < 15 years

15 - < 20 years

< 5 mpy

5 – 10 mpy

> 10 mpy

Transient

Intermittent

Segregated

Nil

10 – 10 5.

Water Cut

Offshore World | 32 | December 2015 - January 2016

10 3 – 10 4

Upto 5%

> 5 – 10%

> 10 – 20%

> 20%

FEATURES Table 3: Failure Vulnerability Rating of Pipelines Sl. No.

Name of line

Age of the Pipeline at the time of Audit

Cor. Rate, mpy

Flow Pattern

SRB Count, No./ml

Water cut, %

Failure Vulnerability rating

WFL-1

8.8

Segregated

10 2

WFL-2

14.8

Intermittent

Nil

WFL-3

15.2

Transition

WFL-4

Intermittent

WFL-5

8.8

Intermittent

WFL-6

Segregated

10 2

WFL-7

12.8

Intermittent

WFL-8

10.8

Segregated

WFL-9

12.8

Intermittent

WFL-10

16.8

Segregated

WFL-11

13.2

Transition

WFL-12

7.2

Segregated

WFL-13

12.8

Transition

WFL-14

9.6

Intermittent

10 2

WFL-15

10.8

Transition

Nil

WFL-16

13.2

Intermittent

WFL-17

10.4

Segregated

WFL-18

16.8

Segregated*

WFL-19

12.8

Segregated*

WFL-20

14.8

Segregated*

corrosion measures such as corrosion inhibitor dosing, pigging and biocide dosing are practiced, vulnerability of the pipelines to corrosion will reduce and the weightage gets discounted. For example, if corrosion inhibitor efficiency is 90%, pigging is in practice and biocide is also dosed regularly, then the vulnerability of pipeline WFL-17 falls to intermediate level with weightage of 36 points.

Similarly Corrosion Audit can be carried out for other infrastructures and assets. Under this broad scheme of Audit, detailed methodology will have to developed, depending upon the nature of infrastructure and asset to be audited. References 1) Anil Bhardwaj and Baldev Raj, “Internal Corrosion of Pipelines”, Pub: Narosa Publishing

Summary On the basis of the studies, following conclusions have been drawn regarding adequacy of corrosion mitigation and monitoring practices that were in place. Remedial measures are also suggested to strengthen pipeline integrity. 1) This pipeline network is ageing, environment is corrosive and there is high risk of leakage in pipelines due to internal corrosion. 2) Corrosion monitoring and mitigation methods are in place, but they need strengthening. 3) The following steps are essential for maintaining integrity of pipelines: a. Planned pigging b. Regular biocide treatment c. Corrosion inhibitor treatment, in batch or continuous mode d. A combination of corrosion monitoring techniques – iron count, ER probe and weight loss coupons.

House, New Delhi, 2014 2) Sankara Papavinasam, “Corrosion Control in the Oil and Gas Industry”, Pub: Elsevier, 2014 3) NACE Test Method, “TM0212-2012 Detection, Testing, and Evaluatio of Microbiologically Influenced Corrosion on Internal Surfaces of Pipelines”, NACE Houston, USA, 2012 4) M-506 CO2 corrosion rate calculation model (Rev. 2, June 2005), Standard Norwegian 5) NACE MR 0175 / ISO 15156, NACE Houston, USA, 2009

Anil Bhardwaj General Manager (Chem) Head - Materials & Corrosion Section IEOT, ONGC Email: bhardwaj_anil@ongc.co.in

Offshore World | 33 | December 2015 - January 2016

www.oswindia.com

INTERVIEW

‘Oil & Gas EPC industry to look forward to India in the years to come’ Traditionally, Indian EPC companies had established a footprint in oil producing countries. However, given the plunging oil prices and India being a consumption market, the infrastructure spending is set to be within India, says Vivek Venkatachalam, Managing Director, IOT Infrastructure & Energy Services Limited (IOT). He shares his thought on the challenges & opportunities laying in the Indian Oil & Gas EPC industry and the future outlook of the industry in the backdrop of falling global crude price and major policy reforms by the government for the hydrocarbon industry, in an email interaction with Rakesh Roy.

The government’s push towards GST and its ‘Make in India’ campaign as well as the new Purchase Preference Policy will lead to a considerable contribution by EPC companies in building the nation.

www.oswindia.com

Offshore World | 34 | December 2015 - January 2016

INTERVIEW Please share your view on Oil & Gas EPC sector outlook in India and the key drivers for the industry? Traditionally, Indian EPC companies had established a footprint in oil producing countries. However, given the plunging oil prices and India being a consumption market, the infrastructure spending is set to be within India. For example, Oil marketing Companies (OMCs) will drive huge infrastructure investments in this sector over the next 5-7 years towards refinery upgradation and to meet the new BS norms. Given this belief, India is the best market to be in for an EPC company today.

What are the challenges EPC contractors facing in executing projects in Oil & Gas Upstream and Downstream in India? EPC players in India face challenges mostly on contract terms and conditions. Unfavourable(non-FIDIC) contractual terms, long approval processes for change orders/claims and back-ended payments are some of the challenges. These delays result in cost overruns and call for the need to educate Indian customers to contract fairly.

The government has proposed many policy reforms for Indian Hydrocarbon sector with the announcement of auctioning marginal fields. According to you, how will the policy reforms improve investors’ sentiment towards Indian oil & gas sector? The opportunities presented by the reforms announced by the government are yet to be explored. We also believe that a lot of it is driven by the uncertainty in oil prices and weak global operating environment. With such unstable and uncertain environment, it has become imperative to move ahead cautiously. Also the slow pace of reforms since last few years has been one of the biggest bottlenecks so far that hinder the growth rate and investment opportunities of the industry. Add to that, the global market volatility has made international investors wary. The proposed policy reforms by the government such as; Pricing and Marketing Freedom for Natural Gas produced from new exploration blocks; and Revenue Sharing Mechanism instead of conventional Profit Sharing Contract will give the much-needed boost to the growth process of the industry. Also Unified License to allow companies to explore oil & gas, shale reserves and coal bed methane; and Open Acreage Scheme – where firms can carve out their own

EPC players in India face challenges mostly on contract terms and conditions. Unfavourable(non-FIDIC) contractual terms, long approval processes for change orders/claims and back-ended payments are some of the challenges.

While the plunging oil price has affected the hydrocarbon industry in whole, what are the strategies IOT has been adopted in protecting its bottom line in such scenario? At IOT, our differentiating factor has been to provide cost-effective execution of projects with world-class quality of construction. We are cautious about our project margins and have been very selective in bidding for new projects during this turbulent period. Regarding our ongoing projects, we have projects in Middle East and Asia Pacific where we have been delivering well at good margins. While the Indian GDP for FY 2015-16 is expected to remain in between 7-8%, according to you how will the Indian Oil & Gas EPC sector contribute to the Indian economy and the factors that will lead the way? In the last few years, given the challenging environment, most EPC companies are undergoing turbulence with varied degrees of impact. But with the government’s push towards GST and its Make in India campaign as well as the new Purchase Preference Policy will lead to a considerable contribution by EPC companies in building the nation.

block at any time without waiting for government auction will be directed towards reviving investor confidence towards Indian oil & gas industry. While taking in account the growing energy needs of the country and PNG, CNG, City Gas requirements, what is your forecast on Indian Oil & Gas EPC sector in providing infrastructure development in this regard? The Distribution infrastructure planned by the Indian Government will drive investments. With over 15 crude oil and product pipelines planned along with tank farms near ports and in the hinterland, there is a lot for the Oil & Gas EPC industry to look forward to in India in the years to come. What are the future plans of IOT Infrastructure & Energy Services for Indian market? We will continue to expand our Energy storage business and strengthen EPC business. In the EPC business, we will continue to focus on areas of competency like Tank Terminals, refinery packages and offsites & utilities through selective bidding. Internally we are also digitizing the business, besides hiring key talent for leaner operations.

Offshore World | 35 | December 2015 - January 2016

www.oswindia.com

FEATURES

AN INDUSTRY RESPONSE TO THE EVOLVING NEEDS OF SUBSEA FLOW ASSURANCE The era of easy accessible oil and gas has ended as oil and gas exploration has gone deeper to deeper from past shallow reservoirs to even greater depths. As such, deepwater subsea production systems must now go deeper and reach further than ever before in order to extract more oil and gas from harsher stores in new locations around the world. While ‘Thermal Insulation’ is an integral part of designing any offshore/subsea product system - especially in deep, cold waters - subsea thermal insulation is perhaps even more pertinent for subsea oil & gas architecture. The article details on the need of effective thermal insulation of subsea structures that helps maintain flow rates, optimise productivity and reduce processing costs; flow assurance is a critical element of deepwater developments.

ue to a continually rising demand for hydrocarbons, the exploration of offshore oil and gas has moved past shallow reservoirs to even greater depths. As such, deepwater subsea production systems must now go deeper and reach further than ever before in order to extract more oil and gas from harsher stores in new locations around the world. As exploration and drilling go deeper, the need for dependable and efficient thermal insulation becomes paramount for deepwater and ultra deepwater developments. Looking at the evolving market for subsea architecture and pipeline insulation coatings, even in these challenging economic times, operators are focusing less on economics and putting increasing emphasis on project specific qualification and product reliability. Going with the Flow Thermal insulation is an integral part of designing any offshore product system, especially in deep, cold waters. This is because effective insulation of subsea structures helps maintain flow rates, optimise productivity and reduce processing costs; flow assurance is a critical element of deepwater developments. However, subsea thermal insulation is perhaps even more pertinent for subsea architecture – insulation materials are used to guard against the buildup of waxes and hydrate crystals in the reservoir fluids which can occur when the hot fluid (oil or gas) is depressurised and exposed to the low seawater temperature at the seabed, or if there is a temporary halt in production. Furthermore, during shutdown, the insulation gives sufficient time for inspection of the pipe and equipment, so engineers can have time to solve production problems and for methanol or glycol injection, as necessary. Unchecked, these deposits can quickly build up and cause loss of flow or even a blockage. Downtime means a loss of revenue, and blockages are expensive to rectify, representing a loss on a considerable investment; the greater the depth, the more the value of that investment. Meeting New Extremes But over the last 10 years subsea oil production has moved to where wellheads are located in water depths in excess of 10,000 feet/3,500 meters and operating temperatures of +350°F/+150˚C and more are commonplace. So, as exploration continues to move into ultra deep waters, the role of insulation in near freezing temperatures becomes ever more critical and investment in high temperature high pressure well heads needs to be protected better than ever.

www.oswindia.com

These extreme temperatures have resulted in an accelerated need for new insulation materials that can keep up with the increasing demands placed on them; many existing insulation materials simply aren’t up to the job and their use could lead to a rapid degradation of performance and also loss in revenue. Not only must they withstand the extreme conditions placed upon them, and perform reliably, they must last the lifetime of a project. Not long ago customers required products that could last 20 years; now it’s often up to 40 years. But it isn’t just manufacturers that have been spurred on by the challenges faced by the offshore industry, developing new solutions that can keep up with the demands of the offshore engineer; operators have also responded to the trend, adapting their approaches to specification to ensure complete peace of mind throughout the entire project, from production and application, through to subsea installation and use. More than ever they understand that in addition to having excellent thermal insulation properties, materials need to protect against corrosion, resist seawater and impacts, be incompressible yet flexible, and not degrade during the life of subsea projects, which is often 40 years or longer. But most of all, they want reassurance that the solution they specify, will continue to perform, now and in the future. An Integrated Strategy Over the last decade, as lessons have been learnt through project failures, offshore operators have begun looking for more robust solutions to give them the project confidence they need to succeed. These failures, combined with ever increasing subsea production temperatures, have meant the reliability of a complete thermal management strategy has never been more apparent. With costs and innovation front of mind when specifying technology, it is evident that generic specifications and product testing are not suitable anymore. Instead, offshore operators want to dig deeper into the insulation material they are specifying and conduct up front project specific qualifications. Subsea thermal insulation must now be tested against specific project parameters, something that historically was rarely heard of. Numerous considerations must be made when evaluating the suitability of a material, and a number of testing programs conducted to ensure that the

Offshore World | 36 | December 2015 - January 2016

FEATURES most appropriate material solution is chosen for any given application. While there is a real lack of subsea insulation qualification standards, particularly compared to other subsea technologies, operators are making sure they go far beyond mechanical integrity concerns and now also qualify the application personnel, equipment and processes, just as stringently. Furthermore, rigorous, project specific qualifications are being set by operators, as well as material screenings in advance of project specific selection. An Issue of Control There has been a significant increase in quality assurance and control measures that must now be taken during application, including an emphasis on operation skill levels, qualification and documentation. This is because the performance of a thermal insulation system is as dependent upon the quality of its installation as it is upon the quality of the material itself. Given the complexity of many subsea structures, the application of insulation material can present considerable difficulties especially in terms of access, efficiency and completion schedules. Inconsistent quality control processes have been one of the main failure mechanisms for insulation systems in the past. Typical issues can include anything from insulation materials applied outside specified ambient temperature ranges, excess air entrapment during mixing resulting in voids in the insulation and measured density values of mixed material outside of the specified range, through to under-supervised, unqualified personnel and insufficient material quantities available during the job. As such, for each stage of production and application, checks now need to be made to ensure complete compliance, as well as an onsite verification of applied systems. Operators have put increasing emphasis on providing concise quality documentation which provides traceability throughout the entire process. Furthermore, this documentation must be integrated with quality plans, manufacturing procedures and job cards to ensure that all application steps are recorded and reported; working this way makes the issue of quality, everyone’s responsibility. In addition, product application could historically be handled by anyone on site, possibly resulting in poor levels of performance; training programs must now be run to ensure the process is more controlled. In factory training of site teams for project specific application procedures is now the norm, as is operator participation in these sessions. Furthermore, minimum levels of experience are required for those applying and working with the materials. Changing with the Times So, in response to this need for better qualification and quality assurance to ensure the reliability of thermal insulation strategies, leading manufacturers have taken steps to make certain that the industry better understands the characteristics of an efficient and effective insulation system. As standard, leading manufacturers have extremely experienced field service teams comprising highly trained professionals to ensure a total insulation service that assures product performance and quality, at all times.

They have also invested heavily in state-of-the-art mixing and dispensing equipment to make sure they have hardware which, when expertly utilised, can provide a functional and robust delivery system capable of applying insulation materials to even the most complex subsea equipment structures. This equipment, which can be modified for specific sites, has been designed to ensure ease of mobility and is housed in specially converted container units for ease of handling. Mobile laboratories and dedicated quality assurance personnel are also provided for projects, as standard. Manufacturers are now more aware that complex field work can incur costs for customers and as such, ensure that all teams are fully briefed on the requirements of each project well in advance to ensure time spent on site is optimized to provide the best value to the customer. A Holistic Approach But it isn’t just about meeting stringent project specific parameters. While this is now tremendously important for operators, and rightly so, more focus is also being given to the solution itself, more specifically the interaction between the anti-corrosion coating and insulation material itself. Instead of viewing these two elements as separate items, operators have begun to see them as entire systems. This is because these two elements are closely connected and the critical failure of either can cause failure to the entire architecture. Instead, operators are looking for total systems which have a single point of responsibility, taking more of a holistic approach to the engineered coatings. This focus on technology isn’t at all surprising, as historically, products have been pushed beyond their maximum operating limits as the definition of and criteria of selecting them was flawed; materials would be selected based on their hot dry service capability rather than designing for worst case, which would be hot wet. The more traditional products such as glass syntactic polyurethanes are particularly susceptible to degradation when exposed to high temperatures and wet applications, and many failures within the industry circled around this technology. This in turn generated a lot of interest for higher operating temperature products, ones that had a more robust nature and were typically unfilled systems. Pioneering the Way This trend has encouraged manufacturers and applicators to develop innovative solutions which can keep up with the increasingly demanding offshore industry. In particular, silicone-based materials have come to the forefront as a more popular solution within the offshore industry due to silicone’s flexible and durable nature. Compared to alternative materials, such as steel and fiberglass, silicone has an extensive temperature range and exceptionally high pressure resistance, it is a flexible material that can damp, seal and protect, and most of all, has an extremely long lifetime. High temperature silicone castable systems offer ease of application and high degrees of automation to the process. They offer lower labor intensity

Offshore World | 37 | December 2015 - January 2016

www.oswindia.com

FEATURES as they are easy to apply and they are not as susceptible to operator error as pack-in-place systems. Increasing Demands However, it’s not always about finding completely new solutions. Manufacturers must continuously look at their current product portfolios to find new ways to make existing products work even harder than they already do, if they are to stay ahead of the game. As such, some leading manufacturers are continually reassessing subsea thermal insulation materials, which have been successfully installed throughout the subsea oil and gas industry for many years, to see how best to enhance their performance in line with these growing demands. An example of the latest generation in subsea insulation solutions comes from Trelleborg; its thermal insulation range of materials including non-syntactic silicone and rubber has been developed to suit a range of environments and applications. With a k-value of 0.13 W/m 2 K, the rubber thermal insulation can be used down to 9,842 feet /3,000 meters deep and at internal temperatures up to +311°F/+155°C, as well as external temperatures as low as -31°F/-35°C. The rubber-based thermal insulation technology consists of a three-layer buildup, which makes up the entire, holistic system. First, an inner layer for corrosion and/or Hydrogen Induced Stress Cracking (HISC) protection; this could be a neoprene compound that is qualified up to +203°F /+95°C, or an EPM compound that is qualified up to +311°F/ +155°C. Both compounds provide excellent corrosion or HISC protection, and have been extensively tested for adhesion, aging and cathodic disbondment. The middle layer has been designed to provide the thermal insulation protection and various compounds are applicable depending on the specific requirements. The compounds provide a k-value of 0.13 W/m 2 K up to 0.19 W/m 2K. The flexibility and stability of the rubber makes this an excellent choice with respect to thermal expansion. The insulation layer is protected by the outer layer. This is a strong and robust layer that provides excellent seawater and mechanical protection and has a successful track record as far back as the early seventies in the North Sea. The other material is based on non-syntactic silicone technology and is ideal for risers and flow lines, subsea trees, manifolds, pipeline end terminations and more, with operating temperatures of -400F/-40°C to +275°F/+135°C and depths of 9,843+ feet/3,000+ meters. The non-syntactic silicone thermal insulation cures at room temperature without exposure to air, making it resistant to cracking and shrinking. In addition to this, the absence of glass microspheres means it provides superior joint strength, increased thermal conductivity, long-term flexibility and increased hydrolytic stability. As it’s not restricted by geometry or thickness limitations, the non-syntactic silicone material can meet a broad range of application specifications. www.oswindia.com

In order to provide even more flexibility when it comes to design and logistics, these thermal insulation systems now also allow for mobile production and can be installed on-site anywhere in the world. These are just two examples that leading manufacturers are responding to the needs of this changing landscape, unfilled systems such as High Temperature Silicones, Polyether Thermosets and Hybrid Polyurethanes are others which are exhibiting stable performance at temperatures in excess of +311°F /155°C. Conclusion Thermal insulation is an integral part of designing any offshore product system, especially in deep, cold waters. This is because effective insulation of subsea structures helps maintain flow rates, optimise productivity and reduce processing costs; flow assurance is a critical element of deepwater developments. As the offshore oil and gas industry continues to push the limits when it comes to demanding subsea applications, the need for reliable and durable solutions that deliver proven performance for critical thermal insulation installations, has never been greater. One of the primar y threats to the integrity of insulation systems is a continued lack of quality control and assurance during the application procedures, whether through human error, or unsuitable environments and locations being used during application. Add to this the lack of subsea insulation qualification standards and it is easy to see why operators are focusing more on making sure the solution they specify is not only right for the job in question, but also applied in line with strict guidance. The fact that the lifetime of an oil field is expected to be a minimum of 25 years and design temperatures of the field can vary throughout (up to +392°F/+200°C), and it becomes clear that it has never been more important for products to prove they can stand the test of time. Products like unfilled systems such as High Temperature Silicones, Polyether Thermosets and Hybrid Polyurethanes are others are exhibiting stable performance at temperatures in excess of +275°F/+135°C. Leading manufacturers are taking great steps to not only develop next generation solutions, but to work with operators to guarantee the reliability, performance and life of a thermal insulation material, through project specific qualification and testing. Through extensive test programming and qualification carried out on these nex t- generation insulation solutions, manufacturers are able to prove the integrity of their service and solutions for the lifetime of the field, providing peace of mind for the offshore operator.

Spencer Allen Regional Account Manager Trelleborg Offshore Email: spencer.allen@trelleborg.com

Offshore World | 38 | December 2015 - January 2016

INTERVIEW

Staying ahead in the Turbulent Time Though the falling oil price and the volatility seen in the international oil markets since second half of 2014 have been affected the global oil & gas industry in whole, International Energy Agency forecast on its ‘India’s Energy Outlook’ – India’s energy demands will be more than double by 2040 and cumulative investment of USD 62 billion in upstream oil, USD 192 billion in refining, USD 127 billion in upstream gas is projected for Indian hydrocarbon sector by 2040 – has created ample opportunities for Oil & Gas EPC/EPCM players in India today, says Arbaaz Malik, Managing Director, Arslan Enginery Limited. He further details on Indian Oil & Gas EPC sector current state & its growth drivers and how has the project design & technical features of EPC/EPCM changed with the changing global oil & gas business environment, in an email interaction with Rakesh Roy.

The MENA Region (Medial East & North Africa) is more organised market, though the entrée barrier for EPC players is high. The Indian market, on the contrary, is easily accessible to new players and thus is more price sensitive than Middle East.

Offshore World | 39 | December 2015 - January 2016

www.oswindia.com

INTERVIEW How do you evaluate the Indian Oil & Gas EPC industry and its growth drivers?

What determines excellence in EPC for Oil & Gas industry? What are the issues related with Oil & Gas EPC in India?

As the falling global crude price has been gloomed the entire E&P activities worldwide, Indian hydrocarbon industry has also suffered like their Global peers. While EPC is considered the lion share of Oil & Gas E&P, the sector has partially affected with the drop of upstream oil & gas activities in the country.

EPC (Engineering, Procurement and Construction) projects are highly schedule driven where phases are overlapped to complete the project as early as possible. Moreover, EPC projects are massive, utilise high skill and well train employee, acquires complex and complicated methodology/technology, needs fast information flow between different phases and close collaboration of multidiscipline as well. EPC projects are facing serious problems like crew idleness, rework and management dilemma which lead to cost overrun and schedule delay.

Meanwhile, International Energy Agency (IEA) on its ‘India’s Energy Outlook’ mentioned that India’s energy demands will be more than double by 2040 as the economy will grow over five times its current size. It is expected that cumulative investment of USD 62 billion in upstream oil, USD 192 billion in refining, USD 127 billion in upstream gas will be coming in Indian hydrocarbon sector by 2040. The Oil and Gas sector plays a vital role in the economic growth of India and will provide ample opportunities to the EPC players. The rising demand of LNG for user industry like power & fertiliser and Natural Gas usage in India is also providing opportunities for EPC as operators are revamping their plants for gas usage. Exploration of untapped oil & gas reserves and CBM blocks along with the latest proposed changing policy regimes from the government will give the mostneeded boost to the upstream oil & gas in the country. These developments will definitely provide opportunities and challenges as well for EPC/EPCM players.

Looking at our country’s long term growth trajectory and growing energy needs, India would definitely offer ample scope for the EPC as well as EPCM players; however, the sector is not without its set of problems that include bureaucratic framework; currency and commodity price fluctuations along with interest rate burden; talent acquisition and retention; shortage of labour and materials; delays in land acquisition; and difficulty in organising funding etc. Over past few years it is observed that the many Indian EPC players are marked their entry into global oil & gas large projects with competent manpower and much more cost-effective approaches.

Keeping in mind the rising downstream oil & gas developments like refinery upgradations for processing of heavy and sour crudes and to meet the new BS norms in the country, the EPC sector has ample opportunities in India today.

Please apprise us Arslan Enginery’s EPC/EPCM services for the entire oil & gas value chain? By building on our success in international markets mainly MENA Region and establishing an exploration and production portfolio, Arslan Enginery aspires to become recognised as a leading international Oil and Gas EPC company. Arslan Enginery’s growth is propelled by a powerful talent pool that provides the company with business acumen, robust systems and processes and pioneering solutions that make it a competitive business. We’re committed to harnessing these talents in an environment that encourages creativity and fosters employee-driven innovation.

Still there are few Semi Government firm like EEPC (Engineering Export Promotion Council), which are guiding & helping Engineering and EPC firm of India to bid global tenders. How has the project design & technical features of EPC/EPCM changed with the changing global oil & gas business environment? Now a days many new IT Companies have jumped into Engineering software data base and many of them are now providing the complete Engineering suite solution - it’s really a big positive point to save time and money. It is advancing day to day regularly and it is becoming back bone of EPC Company.

With guiding principles rooted in world-class customer service, innovation in energy and resource management, and commitment to human capital development, we are working diligently to contribute to the India’s economic and social progress.

With 3D Plant Design Software that includes providing the basic engineering/ FEED and developing the detailed design, EPC contractor can get everything ready in 3D by creating process stimulation. While designing of necessary materials and equipment in EPC/EPCM, we can easily bring up new equipment and by a click we can convert any 3D drawing into 2D drawings with the help of advance technology.

Arslan Enginery provides integrated, cost-effective and sustainable oil and gas solutions. Whether we are working in the heavy oil, offshore, upgrading and refining, gas processing; our goal is always to build and sustain great customer relationships by creating long-term value for their organisations.

IT and technology advancements play a vital role in today’s EPC/EPCM oil & gas in mitigating risk and minimising cost and time. With today’s technological advances, management & administration of the construction site can be up-to-date with site construction and can bring or add amendments at any part with design software.

www.oswindia.com

Offshore World | 40 | December 2015 - January 2016

INTERVIEW How do you compare the EPC/EPCM contracting models in India vis-Ă -vis International projects for the oil & gas industry? The MENA Region (Medial East & North Africa) is more organised market, though the entrĂŠe barrier for EPC players is high. The Indian market, on the contrary, is easily accessible to new players and thus is more price sensitive than Middle East. The Indian market has seen South East Asian players with lower credentials undercutting the market and taking jobs during the last few years resorting to price dumping. There have been cases of serious underperformance and project overruns as a result. Middle East owners have a very stringent pre-qualification process, and only companies with financial standing and performance record are allowed to pass through, and compete in their tenders - entry barrier and filtration process in combination! Moreover, India does not have complete construction workforce to support large and turnkey projects. The civil construction field faces 40 per cent shortage of skilled manpower. The companies should focus on developing the required workforce as a strategy, providing training facilities to meet the increasing demand. Government role is also very important to support in funding for new project across India and we are expecting a new policy to be made by our Honourable PM.

but the global economy too. Indian E&P activities have certainly affected with the turmoil of global oil price and EPC sector has also faced the heat. But keeping in mind the rising downstream oil & gas developments like refinery upgradations for processing of heavy and sour crudes and to meet the new BS norms in the country, the EPC sector has ample opportunities in India today. At Arslan Enginery, a complete EPC solutions organisation for the entire oil & gas industry, we develop our own tools and models through our Energy Insights group to generate a number of proprietary analyses and forecasts. This allows us to support our clients with market diligence, project evaluation, portfolio analyses, business planning and optimisation, among other challenging decisions. We have an extensive global network of downstream specialistsâ&#x20AC;&#x201D;comprising more than 130 consultants who are supported by experts, analysts, and external advisors. To stay ahead, we invest in developing approaches, tools, and data sets across the downstream value chain, including refining capacity, crude and product supply and demand, and equilibrium pricing. To bring clients the best thinking, we develop global, regional, and functional perspectives and explore industry hot topics. What are your plans for the future of Arslan Enginery?

While the current oil price has impacted the whole hydrocarbon industry in whole, what strategies Arslan Enginery has been adapted to protect its bottom line? The falling oil price and the volatility seen in the international oil markets since second half of 2014 have not only impacted the global oil & gas industry

Arslan would be focussed on Gulf as its bread and butter market. Our secondary market is Western, followed by USA. Of course we would not hesitate in pursuing any chance win that can take place outside there. We would also take initial steps needed to enter the fast unfolding trillion-dollar deep water in Bay of Bengal (India).

Now : Mobile App of Offshore World For Android & Apple Platforms Download FREE App from

Offshore World | 41 | December 2015 - January 2016

www.oswindia.com

FEATURES

ESTIMATION OF EACH ACID COMPONENT IN A MIXTURE OF ACIDS USING CONDUCTIVITY TITRATION Acidising is an important aspect of oilfield operations for formation damage removal and increasing or restoring permeability. Depending on the type of formation and its chemistry, either one acid or a mixture of acids of different concentrations can be used, including hydrochloric (HCl) acid, hydrofluoric (HF) acid, acetic acid, formic acid, etc. Sometimes, operators want to know the specific concentration of an individual acid component in the original acid mixtures and/or the concentration in spent acids to evaluate the reaction and consumption of that acid in mixtures under downhole conditions. Currently, analysis of individual acid components in a mixture of acids is fundamentally not possible in field laboratories and requires sophisticated analytical techniques. Also, transporting the acid samples to a well-equipped laboratory can be hazardous. Even a small leak or spill of these highly corrosive chemicals can result in significant incidents. Hence, this paper suggests an analytical technique that can be applied in smaller field laboratories with limited resources and minimum investment to determine individual acid components in mixtures of acids.

ased on the chemistry of the formation, suitable acids or mixtures of acids are selected depending on the required application. For example, acetic acid, formic acid, or HCl acid (of a specific concentration) are used alone or in a mixture in carbonate formations. Treatments in sandstone formations use HCl acid alone or as a mixture with HF acid. Depending on the clay and feldspar concentration, the concentrations of HCl and HF acid are varied. From a quality control view point, individual concentrations of an acid in a mixture are important. Also, the concentration of any acid in a mixture of spent acid adds value in understanding the reactivity of the acid down hole. The concentration of any acid can be determined by titration with a standard alkali solution using a pH indicator solution until reaching the end point (neutralisation reaction). However, in a mixture of acids, total acid can be obtained by the same method, but individual acid concentrations cannot be determined. This paper suggests a titration method involving a conductivity meter that was applied to a mixture of two acids to obtain consistent results. Conductivity titration has been used to determine single acid concentrations; however, it also can be used for two-component acid systems against a standard alkali. This method was not successful for acid systems containing more than two components, as the neutralisation points for particular acids were not clear. This method also did not successfully provide the end point for two-component organic acid mixtures, such as acetic acid and formic acid.

Figure 1: Conductance curve; theoretical conductance titration curve of two acid mixtures vs. NaOH as suggested by Mendham et al. (2000).

Table 2: Neutralisation point of NaOH solution against acids Type of Acid

Sample Strength NaOH Weight of Consumed (g) NaOH (mL)

Table 1: The value of pKa for some important acids

15% HCl Acid

2.07

8.40

Acid

12% HCl Acid + 3% HF Acid

2.42

11.4

Sulfuric acid

Conjugate Acid Conjugate Base Value – pKa H 2SO 4 HSO 4– –10

7.5% HCl Acid + 3% HF Acid

2.20

7.90

HCl Acid

HCl

Cl–

–7

7.5% HCl Acid + 1.5% HF Acid

2.08

5.70

HF Acid

F–

+3.17

12% HCl Acid + 10% Acetic Acid

2.40

11.8

Acetic Acid

CH 3COOH

CH 3COO–

+4.75

12% HCl Acid + 10% Formic Acid

2.02

11.0

Formic Acid

HCOOH

HCOO–

+3.75

10% Acetic Acid + 10% Formic Acid

2.02

8.80

www.oswindia.com

Offshore World | 42 | December 2015 - January 2016

FEATURES Table 3: Neutralisation point determined from conductivity graph for acids Type of Acid Weight (g)

Sample Normality (g) Normality NaOH

Neutralisation Point 1 Neutralisation Point 2

15% HCl Acid

2.07

8.5

12% HCl Acid + 3% HF Acid

2.42

8.0

3.5

7.5% HCl Acid + 3% HF Acid

2.20

4.5

3.5

7.5% HCl Acid + 1.5% HF Acid

2.08

4.25

1.5

12% HCl Acid + 10% Acetic Acid

2.40

8.0

4.0

12% HCl Acid + 10% Formic Acid

2.02

6.75

4.25

10% Acetic Acid + 10% Formic Acid

2.02

This method works on the basis of the pKa value of an acid. An acid dissolution constant, Ka (also known as ‘acidity constant’ or ‘acid ionisation constant’), is a quantitative measure of the strength of an acid in solution. It is the equilibrium constant for a chemical reaction known as dissociation in the context of acid-alkali reactions. In aqueous solution, the equilibrium of acid dissolution can be written symbolically as: HA + H 2 O  A ― + H 3 O + .........................................(1) Where HA is a generic acid that dissociates into A ―, known as the conjugate base of the acid, and a hydrogen ion, which combines with a water molecule to form a hydronium ion. The chemical species HA, A ― , and H 3 O + are considered to be in equilibrium when their concentrations do not change. The dissociation constant is expressed as a quotient of the equilibrium concentrations (in mol/L), denoted by [HA], [A ― ], and [H 3 O + ]. Ka = [A ―][H 3O+] / [HA][H 2O]...................................(2) For more practical purposes, it is convenient to discuss the logarithmic constant, pKa, where pKa = ―log 10 Ka for any acid-alkali reaction. The larger the value of pKa, the smaller the extent of dissociation at a given pH. In chemistry, the Henderson-Hasselbalch equation describes the deviation of pH as a measure of acidity (using pKa, the negative log of the acid dissociation constant), which is useful in finding the equilibrium pH in acid-alkali reactions. The equation is given by: pH = pKa + log 10 ([A ― ]/[HA])...................................(3) In a mixture of acids, an acid with a lower pKa value first participates in a neutralisation reaction, followed by a higher one. In a mixture of HCl and

HF acids, HCl acid should react with an alkali [e.g., sodium hydroxide (NaOH)] before reacting with the HF acid. Similarly, in a mixture of HCl and acetic acid, HCl acid will be neutralised earlier than acetic (Table 1). Experimental Work The tests were performed on different acid mixtures (known concentrations) that are regularly used in oilfield applications, such as HCl acid, a mixture of HCl-HF acid in different concentrations, a mixture of HCl-acetic acid, and a mixture of HCl-formic acid. Total Acid: The total alkali required to neutralise all acid in a mixture was determined by titrating the acid with standard alkali (NaOH, 1N) until reaching the end point (green) using a mixed indicator (75:25) mixture of 0.1% bromocresol green and 0.2% of methyl red. Titration using Conductivity Meter: In brief, conductivity is the ability of a solution to pass an electric current. In solutions, the current is carried by cations and anions. Conductivity depends on a number of factors, such as concentration, mobility of ions, valence of ions, and temperature. In aqueous solutions, the level of ionic strength varies, from the low conductivity of ultrapure water to the high conductivity of concentrated chemical samples. Conductivity can be measured by applying an alternating electrical current (I) to two electrodes immersed in a solution and measuring the resulting voltage (V). During this process, the cations migrate to the negative electrode and the anions to the positive electrode, and the solution acts as an electrical conductor. Both the current and the potential are used to calculate

Table 4: Equivalent weight of acids for acid concentration calculation

Table 5: Individual acid concentration

Acid Type

15% HCl Acid

14.94

12% HCl Acid + 3% HF Acid

12.06

2.88

7.5% HCl Acid + 3% HF Acid

7.47

3.17

7.5% HCl Acid + 1.5% HF Acid

7.45

1.44

12% HCl Acid + 10% Acetic Acid

12.15

10.01

12% HCl Acid + 10% Formic Acid

12.2

9.7

10% Acetic Acid + 10% Formic Acid

Equivalent Weight

HCl Acid

36.45

HF Acid

19.92

Acetic Acid

60.05

Formic Acid

46.03

Type of Acid

Concentration Acid 1

Offshore World | 43 | December 2015 - January 2016

Concentration Acid 2 -

www.oswindia.com

FEATURES Table 6: Total alkali consumption for each acid by either method Type of Acid

Normal Conductivity Titration (mL) Titration (mL)

15% HCl Acid

8.40

8.5

12% HCl Acid + 3% HF Acid

11.4

11.5

7.5% HCl Acid + 3% HF Acid

7.90

8.0

7.5% HCl Acid + 1.5% HF Acid

5.70

5.75

12% HCl Acid + 10% Acetic Acid

11.8

12.0

12% HCl Acid + 10% Formic Acid

11.0

10% Acetic Acid + 10% Formic Acid

8.80

Figure 3: Neutralisation of HCl and HF acid.

excess alkali is introduced. The three branches of the curve (Figure 1) will be straight lines except in so far as (a) increasing dissociation of the weak acid results in a rounding-off at the first end point and (b) hydrolysis of the salt of the weak acid causes a rounding-off at the second end point. For conductivity titration, a known quantity of a sample was taken into a beaker and 100 mL of deionised (DI) water was added. The cell of the conductivity meter was dipped-in and conductivity was measured with constant stirring and the addition of a standard NaOH solution (1N). All tests were performed at 25Â°C. Conductivity was noted for each addition of NaOH, and a graph was plotted for NaOH consumption against conductivity. The neutralisation point was obtained from the graph and final concentration of acid calculated.

Figure 4: Neutralisation of HCl and organic acids.

Results and Discussion Neutralisation Point of Acids Determination using Normal Titration: Total alkali (standard NaOH) consumption for each of the acid mixtures is provided in Table 2. Though the total volume of standard alkali required for determining the neutralisation point can be obtained using this method, the concentration of individual acids cannot be determined in a mixture of acids. However, this method is sufficient for a single-component acid system, such as 15% HCl acid.

Figure 5: Neutralisation of organic acids (acetic and formic).

the conductance (I/V). The conductivity meter then uses the conductance and cell constant to display the conductivity.

Conductivity titration was performed for all of the previously mentioned acids for which normal titration was performed. For each addition of standard alkali (NaOH), a corresponding conductivity value (in ms/cm) was noted. A graph was plotted for standard alkali consumption against the conductivity value. Neutralisation points for individual acids were noted from behavior of the graph (Tables 3 through 5).

Conductivity = Cell Constant X Conductance.............(4) The neutralisation point determination using conductivity titration for a strong acid against strong alkali and weak acid against strong alkali is well known. This concept has been applied successfully for neutralisation point determination for one acid against an alkali. However, this concept has been broadened to determination of the neutralisation point in a mixture of two acids. According to Vogelâ&#x20AC;&#x2122;s chemistry (Mendham et al. 2000), upon adding a strong alkali to a mixture of a strong acid and a weak acid (e.g., HCl and acetic acid), the conductance drops until the strong acid is neutralised, rises as the weak acid is converted into its salt, and finally rises more steeply as www.oswindia.com

For a single-component HCl acid (15%), a sharp decrease was observed in conductivity until the neutralisation point, and then a sudden increase occurred (Figure 2). >> For dual-component HCl and HF acid mixtures, a sharp decrease was observed for HCl acid until the end point. After that, a slow increase in the conductivity value was observed, followed by some consistent points until the neutralisation point for HF acid. As soon as the end point for HF acid appeared, a sharp increase in the conductivity value was observed from the next addition of alkali (Figure 3).

Offshore World | 44 | December 2015 - January 2016

FEATURES >> In cases of HCl and organic acid (acetic and formic) mixtures, a sharp decrease in conductivity was observed until the end point of HCl acid, followed by a slow increase until the neutralisation point for organic acids. From the final end point, a sharp increase in the conductivity value was observed (Figure 4). >> No perfect end point was observed for mixtures of organic acids (acetic and formic) (Figure 5). This could be a result of close pKa values for both acids; acetic acid has a pKa value of 4.75 and formic acid of 3.75.

ADVERTISE TO EXPAND your reach through

Conclusion For determination of an individual acid component in a mixture of acids, the conductivity titration method can be applied. This is a less-expensive method and can be applied in a facility with limited resources. This method might not be suitable for a mixture of acids where pKa values of individual acid components appear close, as in the case of a mixture of acetic and formic acid. In such case, a proper end point cannot be determined. However, this method can be applied effectively for acid mixtures with distant pKa values, as shown in cases of mixtures of HCl and HF acid or mixtures of HCl and organic acids. References: J. Mendham, R.C. Denney, J.D. Barnes, and M.J.K. Thomas. 2000. Vogelâ&#x20AC;&#x2122;s Quantitative Chemical Analysis. Upper Saddle River: New Jersey: Prentice Hall. 525â&#x20AC;&#x201C;527.

INSIGHT INTO THE PHARMACEUTICAL AND BIOTECH INDUSTRIES

Jajati Nanda Senior Chemist Halliburton Technology Email: jajati.nanda@halliburton.com Anil Patil Senior Chemist Halliburton Technology Email: anil.patil@halliburton.com Jyoti Waikar Senior Lab Professional Halliburton Technology Email: jyoti.waikar@halliburton.com

For Details Contact

Jasubhai Media Pvt. Ltd.

Taj Building, 3rd Floor, 210 Dr D N Road Fort, Mumbai - 400 001 Tel: 022-4037 3636, Fax: 022-4037 3635 Email: industrialmags@jasubhai.com

Offshore World | 45 | December 2015 - January 2016

www.oswindia.com

COVER STORY

Is India Ready to Embrace Euro VI by 2020? - By Rakesh Roy

The recent trial phase of odd-even formula for vehicles running in Delhi afterward the Honourable Delhi High Court slammed the Union & State governments after the recent report by the World Health Organization (WHO) which has observed that - Delhiâ&#x20AC;&#x2122;s air ranks among the worst in the world, has sparked much needed debate, particularly on vehicular emission management practices in the country. The situation is not just limited to the capital, but most of the metropolitan cities and now to a significant extent even the B tier cities are facing this issue. In December 2014, WHO had reported that in addition to Delhi, 12 other cities of India featured among the worldâ&#x20AC;&#x2122;s top 20 cities with the highest annual average particulate matter (PM) levels. The report also claimed India to be at number 155 in an environmental quality survey conducted by the World Bank across 172 countries, and unfortunately rated last in terms of air pollution. This is crucial, since the pollutants such as particulate matter (PM) and Oxides of Nitrogen (NOx) form vehicular exhaust are believed to be the major pollutants of the air quality in Indian cities. Over the last decade, many Indian cities have undergone rapid urbanisation and witnessed significant increase in number of motor vehicles which has led to an increase in vehicular pollution, a matter of great concern!! Recently, the Union government has announced developing 100 smart cities across the country, which will further add to the number of vehicles and add to the pollution woes. The government has benchmarked the vehicular emission standards and defined maximum permissible limits for pollutants such as PM and Oxides of Nitrogen (NOx) to match the European (Euro) Standards since 2000. Currently, for light and heavy-duty vehicles, India follows the Bharat Stage (BS) IV standards (based on Euro 4) in major cities and BS-III (based on Euro 3) in the rest of India.

www.oswindia.com

Offshore World | 46 | December 2015 - January 2016

COVER STORY Indian Emission Standards (4-Wheel Vehicles) Standard India 2000

Bharat Stage II

Reference Euro 1

Euro 2

YEAR

Worldwide Implementation of Euro VI Emissions Norms Region

2000

Nationwide

2001

NCR*, Mumbai, Kolkata, Chennai

2003.04

NCR*, 13 Cities †

2005.04

Nationwide

2005.04

NCR*, 13 Cities†

USA: Sulphur content in diesel across USA is limited to 15 ppm. There are varying limits for sulphur in gasoline. It is 80 ppm for the country with the exception of California, where different grades of ultra-low sulphur gasoline are in use with limits of 15, 20 and 30 ppm. However, for the country (except California) refiners are constrained within an annual average of 30 ppm sulphur in gasoline.

2010.04

Nationwide

Japan: Japan moved to 10 ppm sulphur fuels – both diesel and gasoline – in 2008

NCR*, 13 Cities†

Canada: Canada limits sulphur in gasoline to 80 ppm, while that for diesel is 15 ppm. Further, all primary suppliers must meet a sulphur average of 30 ppm. The per gallon cap for Benzene is 1.5% vol. max with an annual pool average of 0.95% vol., or, a flat batch limit of 1.0% vol.

Bharat Stage III

Euro 3

Bharat Stage IV

Euro 4

2010.04

Bharat Stage V

Euro 5

(to be skipped)

Bharat Stage VI

Euro 6

2020.04 (proposed)

Entire country

* National Capital Region (Delhi) † Mumbai, Kolkata, Chennai, Bengaluru, Hyderabad, Ahmedabad, Pune, Surat, Kanpur, Lucknow, Sholapur, Jamshedpur and Agra Indian Emission Standards (2 and 3 wheelers) Standard

European Union: The European Union (27 countries) have introduced 10 ppm sulphur Euro V gasoline and diesel fuels since 2008-09 and has moved to Euro VI fuels – sulphur limit to 10 ppm in 2014.

Reference

Date

Bharat Stage II

Euro 2

1 April 2005

Bharat Stage III

Euro 3

1 April 2010

Bharat Stage IV

Euro 4

1 April 2012

Bharat Stage V

Euro 5

1 April 2017 (to be skipped)

Bharat Stage VI

Euro 6

2020.04 (proposed)

Source: Auto Fuel Vison & Policy 2025

In global comparison, implementation of best-in-class emission norms presently – Euro V & VI, where many Western & European countries and even its Asian counterpart Japan and China have already implemented Euro V & VI (equivalent to BS V & VI) in their major cities, India is still far behind and has a long way to go. Considering a long-term air quality improvement plan, a robust commitment requires to integrating clean transport strategies that fundamentally change both fuel and technology currently in use. The ‘Auto Fuel & Vision Policy 2025’ of India, proposed rolling out nationwide BS-IV, BS-V, and BS-VI (based on Euro IV, Euro V, and Euro VI) over a staged timeline by 2017, 2020, and 2024 respectively. However, with the increasing air pollution in India, the latest government’s decision to skip Bharat Stage V (equivalent to Euro V) emission diesel & petrol fuel norms to advance the standard for cleaner motor vehicles and leapfrog to Bharat Stage-VI (equivalent to Euro VI) emission norms countrywide by April 2020 can be perhaps be seen as India’s boldest move to curb air pollution. Compliance with Euro VI (equivalent to BS VI) in the stipulated timeframe would require adherence from two key sets of stakeholders — Oil Refineries and Automobile Manufacturers. Refineries are required to manufacture, test and supply fuel meeting the prescribed norms of Euro VI and Automobile Manufacturers will have to produce and sell vehicles with the requisite engine emission control technologies and engine compatibility.

Australia: In 2009 Australia moved to 10 ppm limits for sulphur in gasoline and diesel, from 50 ppm previously, in effect from 2006 for diesel and 2008 for gasoline. Korea: Korea limited sulphur in both gasoline and diesel to 10 ppm, starting 2009. Mexico: In Mexico, Sulphur content in gasoline is 80 ppm, with 30 ppm gasoline available in three major metropolitan areas, which is proposed to be extended nationwide. The limit for sulphur in diesel is 500 ppm country wide. In three major metropolitan areas and on the US border diesel with 15 ppm is available. It is proposed to set the standard at 50 ppm for diesel country wide from 2015. China: China has selectively introduced Euro IV equivalent fuels in Beijing, Shanghai and Guangdong, while Euro III equivalent fuels are sold in rest of the country. In February 2013, China announced a timeline for implementation of 10 ppm sulphur fuel standards – China V standards – for both gasoline and diesel. Hong Kong, Taiwan and Singapore: Auto fuel sulphur content in all three has been restricted to 10 ppm. Brazil: For diesel, Brazil in 2010 entered in a phase of transition from 1,800 ppm sulphur to 500 ppm, set to go countrywide from 2014. Further timelines have not been indicated. Gasoline sulphur country wide used to be 1,000 ppm till 2013 and from 2014 is set to a maximum of 50 ppm. In select metropolitan centres and regions the stipulated sulphur limits are set at lower levels. South Africa: In South Africa, there are national level and specific tighter local norms. The national sulphur limit for diesel was 500 ppm generally and 50 ppm in specified locations. In 2017, country wide the sulphur limit is set to be reduced to 10 ppm. The present sulphur limit for gasoline is 500 ppm, but this is set to be reduced to 10 ppm starting 2017. Russia: The present limit for sulphur in diesel and gasoline is 350 ppm and 150 ppm respectively. These are proposed to be reduced for both diesel and gasoline to 50 ppm in 2015 and to 10 ppm in 2016 . Thailand: The sulphur limit for both diesel and gasoline has been set to 150 ppm since 2005, which is proposed to be lowered to 50 ppm from 2017. Malaysia: The sulphur limit for both diesel and gasoline has been set at 500 ppm. The changeover to 50 ppm is expected from 2015. Indonesia: The sulphur limit for both diesel and gasoline is set at 500 ppm. There are proposals to lower the threshold to 50 ppm. Source: Auto Fuel Vison & Policy 2025

Offshore World | 47 | December 2015 - January 2016

www.oswindia.com

COVER STORY

Simply Put: How does India Prepare to Leapfrog to Euro VI by 2020 Four years from now, the government wants to leap directly to BS-VI auto emission norms from the existing BS-IV, skipping BS-V. But the challenges, before both Oil Refineries and Automakers, are enormous. However, Environment & Climate watchdogs like Central Pollution Control Board (CPCB), and Centre for Science and Environment (CSE) and National Green Tribunal (NGT) have hailed the governmentâ&#x20AC;&#x2122;s move to leapfrog to Euro VI emissions standards by 2020. Offshore World sought views of key leaders from Oil Refineries and Automotive Makers of India on their capabilities and their strategies to deal with the issue. Also Environment & Climate Monitors shared their thoughts on this. Excerpts:

www.oswindia.com

Offshore World | 48 | December 2015 - January 2016

COVER STORY Changes in the Refining Business and Implementation of Euro VI by 2020 The changing global oil & gas business environment has mandated Indian refineries to switch over to cheaper crudes, which in general are heavy and contain high sulphur to keep higher refining margins. Also refineries have to comply with the stricter regulations and fuel compliances like BS IV & V in the stipulated time earlier fixed by the government. For enhancing the processing capability of such crudes and comply with the fuel compliances, huge investments have been made in some refineries and are required in others for upgrading bottom of the barrel to maximise distillate yields. Amidst this situation, switching over to 100 per cent Bharat Stage VI (Euro VI) quality by 2020 will result in further technological interventions/innovations to meet the stipulated auto fuel quality. Indian refiners need to invest USD 4.5 billion (` 300 billion) to produce Euro VI complaint fuel, according to Nitin Gadkari, Union Transport Minister.

Mumbai Refinery will install new Gasoline Hydro-treater Unit (GTU) at an estimated Capex of ` 554 crores for BS VI MS and replace the catalyst in DHDS unit at a cost of approx ` 100 crores for BS VI HSD production. Kochi Refinery will set up new NSU, NHT/CCR and ISOM units at a capex of ` 3325 crores for production of BS VI MS. Units being installed as part of ongoing Integrated Refinery Expansion Project (IREP) at Kochi will be capable of producing 100 per cent BS VI HSD on completion of new MS units. BPCL‘s joint venture refinery at Bina (BORL) has taken fuel quality upgradation to BS VI level for existing refinery capacity also as part of debottlenecking project to increase capacity from 6 to 7.8 MMT with total capex of ` 3075 crores. Project is expected to be completed during the year 2018. Numaligarh Refinery (NRL) is installing a new DHT unit which is expected to be completed by March 2018. With minor debottlenecking of existing MS block, NRL will be able to produce 100 per cent BS VI auto fuels. H Kumar: Mangalore Refinery, a subsidiary of Oil and Natural Gas Corporation Limited (ONGC), with 15 MMTPA Refiner y capacity and Nelson Refiner y complexity index of around 10.0 is a blend of state-of-the-art technologies and a motivated work force.

B K Datta: BPCL is fully geared up to produce 100 per cent BS VI auto fuels as per the government plans. All BPCL group refineries have completed the required configuration studies and finalised the technologies / projects which are required to be implemented for production of BS VI auto fuels. Some of the projects are already under execution and necessary approvals for two new projects will be obtained by 12 th February 2016. BPCL group refineries i.e. Mumbai, Kochi, subsidiary Numaligarh and JV refinery at Bina are expected to invest approx ` 5,000 crores to produce BS VI auto fuels in addition to approx ` 10,000 crores already being spent for BS IV auto fuels production. All new projects will be completed in a span of maximum 3 years after obtaining environment clearance which means all BPCL refineries will be fully ready to produce 100 per cent BS VI auto fuels by the end of the year 2019. Skills available in our Refineries are fully capable to adopt the new technologies for production of BS VI auto fuels.

MRPL’s Phase I - Refinery, with capacity of 3.69 MMTPA was commissioned during March 1996, and Phase – II Refinery of 6 MMTPA capacity during November 1999. MRPL has further expanded its capacity to 15 MMTPA in March 2012 under the Phase-III refinery expansion cum up-gradation project which also aims at bottoms upgradation and production of petrochemical feedstocks. All the units of the Phase-3 expansion project have been commissioned, the last unit PFCCU commissioned in August-2014. In addition, MRPL has also set up a 0.44 MMTPA Polypropylene Unit and a Single Point Mooring (SPM) facility off the Mangalore Coast. The commercial production from the Polypropylene unit was commenced from 16th June 2015 onwards. The total cost of the projects undertaken by MRPL was at around ` 15,000 Cr. With the above expansion MRPL today can produce entire quantity of HSD and MS, compliant to the BS IV grade specification. Notably MRPL was also one of the first in the country to make this quality. It is presently supplying this quality as per the demand of Oil Marketing Companies (OMC). Earlier Ministry had constituted an Expert Committee on 19.12.2012 under the chairmanship of Dr Saumitra Chaudhary, Member, Planning Commission for drafting the Auto Fuel Vision & Policy, 2015. The Committee has, interalia, been entrusted to recommended roadmap for Auto Fuel quality till 2025 for the country. The Committee submitted its report on 02.05.2014. As per recommendations of the Committee, Ministry has notified vide letter dated

“All new projects will be completed in a span of maximum 3 years after obtaining environment clearance which means all BPCL refineries will be fully ready to produce 100 per cent BS VI auto fuels by the end of the year 2019.” - B K Datta, Director (Refineries), BPCL Offshore World | 49 | December 2015 - January 2016

“MRPL can make certain quantity of BS-VI diesel today also with the present configuration but the entire quality can be converted to BS VI with certain changes in catalysts in the diesel treatment units.” - H Kumar, Managing Director, MRPL www.oswindia.com

COVER STORY “NRL is taking actions to meet requirements of Auto Fuel Policy and will be ready to produce HSD and MS with BS-VI specifications by 2020.”

Fall in Line: Automakers Agree to Comply Euro VI by 2020 Amidst the rising concerns portrayed by the Indian automotive industry, the government has decided to stand by its decision of pushing forwards the date of implementation of Bharat Stage VI (Euro VI) emission norms to 2020. According to Automotive Industry, the change to BS-VI is reported to cost the entire industry and its supporting industries, anywhere between ` 70,000 crore-90,000 crore.

- P Padmanabhan, Managing Director, NRL 19.1.2015 a schedule for supply of BS IV fuels in the entire country by 1.4.2017 in a phased manner. Further, Ministry has instructed OMCs to prepare for introduction of BS-VI fuels w.e.f. 2020. MRPL can make certain quantity of BS-VI diesel today also with the present configuration but the entire quality can be converted to BS VI with certain changes in catalysts in the diesel treatment units. For meeting BS VI MS, MRPL would need to treat some of its MS blend pool streams for which some additional hardware has been envisaged. MRPL has already applied for the statutory clearances for the project to commence work. The project schedule has been worked out and the target is kept to produce BS VI grades HSD and MS before 2020, meeting the product specification as mandated by the Auto fuel Policy 2025. The talent pool and skill set of MRPL’s workforce have been nurtured by way of performance oriented meritocratic systems and a healthy work culture. The management is focused to keep the refinery nimble and alert to changes in the environment and to encash any opportunity presented by changes in the global hydrocarbon scenario. The changes in the oil sector are unprecedented by its speed and depth. Given the able guidance of the political leadership in the country, the refining industry is coaxed to be become adept to the ground shaking changes. Emphasis on cleaner fuels and leap frogging to BS VI instead of BS V are certain signals of this policy framework. It can be summarized that the leadership of the country and management are in perfect synch to understand the policy objective and MRPL is committed to achieve the set objectives. P Padmanabhan: NRL has always been proactive in adopting green technology and its products have been in compliance with specified norms. At present, the Refinery is producing its entire quantity of MS conforming to BS-IV grade along with limited quantity of HSD conforming to BS-IV grade. Moreover, the Company is taking actions to meet requirements of Auto Fuel Policy and will be ready to produce HSD and MS with BS-VI specifications by 2020. We are currently setting up a DHDT (Diesel Hydrotreater) of 0.7 MMTPA capacity at a cost of ` 1,031 crores to produce HSD with BS-IV specification. The plant will be commissioned in the year 2018. The same plant with minor modification will be capable of producing HSD to meet BS-VI standards as specified by 2020.

Vinod Dasari: To implement Euro VI emissions norm on the stipulated time by 2020 will be extremely challenging task but as an industry in whole, we will work a way so that all new models will come with BS VI from 2020. As the capacity of Ashok Leyland, our company will invest whatever resources required to comply with regulations. Shekar Viswanathan: The current levels of pollution in major cities such as Delhi and Mumbai have jackknifed the government into action. Very recently the government’s legal representative committed before the Honorable Supreme Court that the government will make all efforts to supply Bharat Stage 6 (equivalent to Euro VI) fuel by 2020. Currently the government supplies a mix of Bharat Stage 3 and Bharat Stage 4 fuel across the country and has again reconfirmed that Bharat Stage 4 fuel will be available pan India by 2017. So far so good but it affects the players - the oil industry, the auto industry, the consumer and the government in different ways. But first the levels of pollution - if one examines the daily Plume report which gives on a real time basis the extent of pollution in different cities New Delhi

Numaligarh Refinery is currently producing Motor Spirit (MS) with BS-IV specification in its MS plant. For production of BS-VI grade of MS, the existing plant will require minor de-bottlenecking. These modifications will be completed well in time to produce MS which meets BS VI standards as specified by 2020. NRL’s present manpower is highly skilled and capable of operating the above mentioned plant. Required functional training and recruitment will be carried out as and when required to fill the gap, if any. www.oswindia.com

Offshore World | 50 | December 2015 - January 2016

“Ashok Leyland will invest whatever resources required to comply with regulations,” - Vinod Dasari, President, Society of Indian Automobile Manufacturers, and Managing Director, Ashok Leyland Limited

COVER STORY “For the auto industry in particular, this will prove to be a difficult task in adapting the engines and drive trains to the new Bharat Stage 6 fuel particularly since the country will be leapfrogging the Bharat Stage 5 fuel availability.” - Shekar Viswanathan, Vice Chairman and Whole-time Director, Toyota Kirloskar MotorDirector, Ashok Leyland Limited

“Union government’s move to leapfrog to Euro VI emissions standards in 2020 is a great move.”

and Mumbai are the worst cities to live in. The Plume index which captures all pollutants and arrives at an index shows the 2 Indian cities to be above 250, that is Extreme Pollution, while an equally densely populated city like Tokyo shows the index to be at a benign 25 and denotes the pollution level as Fresh Air.

Euro VI by 2020 - A Great Step Forward: CSE CSE welcomes the landmark decision of the Union government to skip Euro V emissions standards and leapfrog to Euro VI standards in 2020. With this, India will take the first step towards fuel-neutral standards that will lower the gap between emissions standards for diesel and petrol vehicles. CSE research shows that this step was urgently required to address the concerns over emissions from the current diesel technology. As India leaps from Bharat Stage IV to Euro VI, particulate emissions from diesel cars will be reduced by 68 per cent; NOx emissions can come down by 82 per cent. Reduction from heavy duty vehicles will be 87 per cent and 67 per cent, respectively, for particulates and NOx.

Other fuels such as gasoline and CNG which do not spew as much PM 2.5 as diesel nevertheless give out other pollutants such as carbon monoxide and carbon dioxide in greater quantities. There is therefore much merit in moving quickly to Bharat Stage 5 and Bharat Stage 6 fuels which drastically reduces the extent of pollutants and in the case of diesel reduces particulate matter (PM) & enables it to come on par with gasoline. While the oil industry has tentatively found the financial resources to make available Bharat Stage 6 fuel by 2020 it is going to be a tough road ahead for them to implement this project given the short lead time to make compatible the tank farms and product pipelines to the newer fuel. In the past too when there was an upgradation sequentially from BS-I to BS-IV, the oil industry has been unable to meet the targeted timelines. For the auto industry in particular, this will prove to be a difficult task in adapting the engines and drive trains to the new Bharat Stage 6 fuel particularly since the country will be leapfrogging the Bharat Stage 5 fuel availability. Cars need to be tuned to an India driving cycle and it is only through a process of iteration can vehicles be optimised in fuel efficiency and emission levels. It must be recognised that cars in India need to be designed in such a manner that it accommodates the diesel particulate filter (DPF) and the selective catalytic reducer (SCR). This may violate length norms which forms the basis of excise taxation of vehicles in India. So as a result if cars cannot meet the sub 4 meter category then such cars would implicitly get taxed at an excise rate of 24 pct instead of the more benign 12 pct.

- Anumita Roy Chowdhury, Executive Director, Centre for Science and Environment

We believe this is a game-changer decision and will help India leapfrog to much cleaner emissions. This is needed at a time when India is motorising very rapidly. The number of vehicles that India will add in the next decade is over twice the current vehicle stock in the country. Stringent emissions standards are needed to reduce the pollution impact of this immense motorisation. The current emissions standards of Bharat Stage IV in a few cities and Bharat Stage III in the rest of the country are 10 to 15 years behind the norms followed by Europe. These outdated emissions standards allow diesel vehicles to emit several times more nitrogen oxides and particulate matter compared to petrol vehicles. The government’s latest move will reduce the time lag with Europe to just six years in 2020. It is unfortunate that India has already lost a lot of time in announcing the next level of emissions standards roadmap. After implementing Bharat Stage IV emissions standards and Bharat Stage III in 2010, India had virtually remained without any further roadmaps for improvement in emissions from vehicles. This also means that until 2020 -- other than expanding the current Bharat Stage IV emissions standards -- India would not have moved forward. All this while, motorisation would continue to explode based on 10-15 year old emissions control measures. It is noteworthy that the decision to leapfrog to Euro VI has been possible because Indian refineries have agreed to supply Euro VI-compliant fuel by 2020. This paves the way for introducing advanced emissions control systems in vehicles that are needed to clean up the exhaust more efficiently. Only 10 ppm sulphur fuels will allow use of these advanced systems.

The impact on the consumer is going to be financial particularly as he has to pay for cleaner fuel (BS 6). The cost of such vehicles would also tend to increase though it is very uncertain by how much this would increase. But at the end of the day even with advent of Bharat Stage 6 fuel would pollution levels come down? The answer is NO unless the government mandates a scrapping policy that will effectively remove Bharat Stage 1&2 and Bharat Stage 3 vehicles off the roads in a systematic manner.

CSE research says the immediate next step should be to ensure that the current Bharat Stage IV emissions standards in force in Delhi and a few other cities is made uniform nation-wide by March 2016. This is urgently needed to cut emissions from Bharat Stage III trucks by 80 per cent. Alongside, it is important to restrain diesel cars as diesel exhaust is extremely toxic. As India now gears up to bring in a new genre of emissions control technology, it should also have in-use compliance regulations in place to ensure that these systems work optimally throughout the useful life of vehicles on our roads, and manufacturers are held accountable – as it the global good practice.

It must not be forgotten that vehicles account for less than 20 pct of PM 2.5 pollutant the government must focus on reducing the remainder of the PM 2.5 pollutant from non-vehicular sources.

While welcoming this proactive move by Central government, CSE hopes that the automobile industry will enable scheduled implementation of this decision to help reduce public health risk in the country.

Offshore World | 51 | December 2015 - January 2016

www.oswindia.com

CASE STUDY

FIRST SUBSEA GAS COMPRESSION SYSTEM IN WORLD: MILESTONE IN SUBSEA TECHNOLOGY The paper details on the world’s first subsea gas compression system that was went on stream at the Statoil-operated Åsgard field in the Norwegian Sea and delivered jointly by Statoil and Aker Solutions to improve oil recovery. Traditionally compression plants are installed on platforms or onshore but this subsea gas compression system was located in 300 meters of water and will add approximately 306 million barrels of oil equivalent to the total output over the life of the field.

n September 2015, the world’s first subsea gas compression system went on stream at the Statoil-operated Åsgard field in the Norwegian Sea, delivered jointly by Statoil and Aker Solutions. This success is a major milestone in the subsea industry. It has opened the door for new oppor tunities in deeper waters, and in areas far from shore. Subsea compression will add approximately 306 million barrels of oil equivalent to the total output over the life of the field. This is one of the most demanding technology projects aimed at improving oil recovery. Extending Field Life In the early 1980’s tremendous efforts were made in Norway to increase the competence of transport of oil and gas in the same flow-line. This is called multiphase flow. During that time many questions arose. Is it possible to transport oil and gas over long distances in the same flow line? Would the transport just stop? Would it produce enormous slugs and would this lead to depletion of reservoir pressure? Since Åsgard is produced through multiphase flow, as the reservoir pressure decreases, it approaches a minimum flow condition, where it cannot

www.oswindia.com

produce anymore. In order to extend the life of the field and recover more hydrocarbons, compression is required. Traditionally compression plants are installed on platforms or onshore, but this plant is located in 300 meters of water. This is due to that fact that the closer to the well that compression takes place, the more hydrocarbons can be recovered. Placing the compressor station on the seabed near the wellheads, rather than on a platform, improves recovery rates and reduces capital and operating costs. Moving the gas compression from the platform to the wellhead also substantially increases life of the field. In addition to improving recovery, subsea gas compression is more energy efficient than the traditional topside solution. The technology reduces significantly energy consumption and CO 2 emissions over the field’s life. Case History In December, 2010, Aker Solutions was awarded the contract by Statoil to deliver the Åsgard subsea gas compression system, which consists of modules for three identical sets (two installed and one spare) of compressors, pumps, scrubbers, coolers and related power distribution equipment fitted together in a common subsea template. These components

Offshore World | 52 | December 2015 - January 2016

CASE STUDY

were delivered to Statoil ready for installation on the seafloor of the Åsgard field in the Norwegian Sea.

of the SCSt to the existing pipeline system and ensure flexibility in routing of the production to Åsgard B for further processing.

The objective of the Åsgard Subsea Compression Project is to provide and install a subsea system at the Åsgard gas field. The subsea compression system is controlled from Åsgard B platform and power is provided from Åsgard A FPSO.

Establishing the necessary support functions onshore has been an important and substantial part of the project. For Compression system to work efficiently, all modules in each train should be operational at any given point of time. Malfunction in any one of the module will jeopardise the end result. In such an event a spare compression train is stored in custom designed halls at the onshore supply base, Vest base; such that any damaged module is quickly replaced and operation continues. Advanced condition monitoring system is provided, helping ensure operational excellence.

The facility comprises of two 11.5-megawatt compressors for the Midgard and Mikkel gas reservoirs. The two gas compressors are installed on the seabed located close to the wellheads. Gas and liquids are separated out prior to the gas compression process. After pressure boosting, they are recombined and sent

Moving the gas compression from the platform to the wellhead also substantially increases life of the field. In addition to improving recovery, subsea gas compression is more energy efficient than the traditional topside solution. through a pipeline about 40 kilometers to Åsgard B. Recovery for the Midgard reservoir on Åsgard will increase from 67 per cent to 87 per cent, and from 59 per cent to 84 per cent for the Mikkel reservoir. This project consists of one subsea compression manifold station (SCMS) and one subsea Compression station (SCSt). SCSt comprises of two parallel, identical compression trains, including hermetically sealed centrifugal compressors. Each compressor train comprises of coolers, pumps, separators and MEG modules. The purpose of the SCMS is to provide an efficient tie-in

Challenges A total of 22 modules of var ying shapes and sizes are installed and connected. The smallest modules are installed through Moonpool Handling System (MHS) and larger ones are installed through Special Handling System (SHS). The main challenge in designing and installation of these modules was that they are to be deployed and retrieved at a significant wave height of 4.5m. These new installation systems challenged the team to design the modules to meet the most stringent interface and functional requirements.

Offshore World | 53 | December 2015 - January 2016

www.oswindia.com

CASE STUDY The objective of the Åsgard Subsea Compression Project is to provide and install a subsea system at the Åsgard gas field. The subsea compression system is controlled from Åsgard B platform and power is provided from Åsgard A FPSO. Furthermore, the compressor trains induce vibrations in the structural and piping system during operation. Hence, it was equally important to design complete modules not only for the pressure and temperature from the reservoir but also for the dynamics because of this rotating equipment. A detailed study was carried out at the engineering stage to address all vibration related issues. Engineering Details As mentioned above, the purpose of this system is to increase the pressure of the incoming fluids to a pressure suitable to sustain and accelerate production, and maximise recovery with operation at reduced wellhead pressure. The process system has the following functionality: • The incoming multiphase well fluid is cooled • The well fluid is separated in a scrubber into gas and liquid streams • The gas stream is pressurised in a centrifugal compressor • The gas stream is cooled in a discharge cooler • The liquid stream is pressurised in a centrifugal pump • The gas and liquid streams are recombined and flow to the topside as a multiphase stream The inlet cooler has two functions: it cools the inlet well stream and it serves as anti-surge cooler. It is designed as passive coolers (natural convection) with seawater on the external side. The scrubber removes liquid and solids from the gas, and produces a gas stream suitable for compression. The design also ensures stable operation during a liquid surge, with minimum use of level control devices and minimum impact on compressor operation due to inlet pressure transients. The inlet piping has been optimised to maintain separation in the piping prior to entering the scrubber. The compressor module is the heart of the compressor system. It is an integrated motor compressor, which features an active magnetic bearing control system. The main process outlet connects to the discharge cooler; the anti-surge line is routed back to the inlet cooler. The compressor is driven by an 11.5 MW motor, operated by a variable-speed drive (VSD) located on the topside. The active magnetic bearing (AMB) system controls the magnetic bearings integrated in the motor-compressor unit; related electronics and power amplifiers are housed in a separately retrievable control module. The subsea compression process is controlled by a Safety Automation System that is designed to perform monitoring, operation and supervisory control, data computation and operational analysis. The compressor module also features a High Voltage (HV) Connection System that connects the compressor module to its HV supply from the compressor transformer module. www.oswindia.com

The discharge cooler cools the compressor discharge gas flow such that the temperature does not exceed 80°C downstream of the cooler. The discharge temperature from the compressor is influenced by the inlet temperature, the compressor efficiency and the compression ratio. The pump modules’ main feature is a 5-stage centrifugal pump of Aker Solution Liquid Booster type. The first stage is a double suction impeller, designed to meet the Net Positive Suction Head Required (NPSHR) conditions when pumping condensate. The rated shaft power is 750 kW. HV power is provided via a HV flying lead coming from the pump transformer. The MEG module distributes the Mono Ethylene Glycol (MEG) via the internal piping to all the process modules. MEG is used for preservation and hydrate prevention. The MEG module is also used for displacement of hydrocarbons from the modules and to the discharge stream towards the SCMS. Two CPDU (Control Power Distribution Unit) Modules are located on the SCSt Umbilical Termination Area (UTA) deck and supply power to all low voltage power consumers on the SCSt and SCMS, i.e. SCM, actuators and AMB control systems. Operation Overview The system is designed in order to be able to operate in various configurations: 1. Two compressor trains running in parallel 2. Two compressor trains running in parallel with tandem compressors 3. Two compressor trains running in series The existing compressor trains, consisting of a single subsea compressor on each train, increases the pressure to extend the life of the field. As the production continues throughout the years, an increased pressure ratio will be required. Therefore for the late phase development of the Åsgard Subsea Compression options like replacing the existing compressor modules with tandem compressors (providing a more than double pressure ratio within the same footprint) are under evaluation and will be further matured through a separate project.

Sanjay Kulkarni Principal Engineer – Structural Engineering Department Aker Powergas Subsea Pvt Ltd Email: Sanjay.Kulkarni@akersolutions.com

Offshore World | 54 | December 2015 - January 2016

FEATURES

MOST ENERGY COMMODITIES CONTINUES TO DRAG DOWN ENERGY COLUMN (PRICE REVIEW): NOVEMBER - DECEMBER 2015

Most energy commodity prices continued to decline in the two-month period of November and December 2015, in line with past few months’ trend. NYMEX heating oil futures declined the most by 26.6 per cent on weakness in crude oil. On the other hand, NYMEX natural gas futures managed to close two-month period up by 0.7 per cent over October’s close.

YMEX (CME) crude oil (light sweet) futures started the month of November at USD 46.14 per barrel, down by a per cent from previous month’s close, largely due to the release of lackluster data on Chinese factory activity and reporting of jump in Russian oil production. Later, oil prices recovered on concerns over supply disruptions in Libya and Brazil. In Libya, the oil export terminal of Zueitina was blocked by an armed militia; while in Brazil, where the country’s largest public-sector union, which represents oilplatform workers, went on a strike. Notably with oil prices then moving down almost through the two-month period, NYMEX crude oil futures registered its eventual two-month-high of USD 48.36 per barrel on November 3. Thereafter weekly US government data showing that crude oil inventories rose for a sixth week in a row triggered the fall in oil prices. Strength in the dollar added to pressure on crude-oil prices. Later, a data release showing strongerthan-expected US October jobs report lifting expectations of US Fed rate hike in their December meet ensured further fall in oil prices. Subsequently, data release from China (crude oil imports in October dropped 5.7 per cent from a month earlier) feeding concerns about slowing energy demand added to the bearish sentiments. Later data showing a seventh consecutive weekly increase in US crude supplies and a monthly IEA report showing a forecast for slower growth in global oil demand next year, kept oil prices on a downtrend. Intermittently, falling oil prices had brief respites on news that output from the Organization of the Petroleum Exporting Countries saw third consecutive

monthly decline as well as on France’s airstrikes in Syria raising concerns over potential supply disruptions in the Middle East. However worries over growing global oil supply amidst sustained rise in US oil inventory levels ensured oil prices remained on downtrend. Again by fag-end of November, oil prices staged some recovery as tensions between Turkey and Russia raised concerns over the possibility of disruptions to energy output in the region. Incidentally, Turkey shot down a fighter jet claimed by Russia after it apparently crossed into Turkish airspace. Reports of Saudi Arabia’s pledge to work with global oil producers in an effort to stabilize prices also helped recovery in oil prices. But then again release of EIA data indicating robust US crude oil production along with looming US crude stockpiles at levels unseen in at least 80 years pulled oil prices lower. Strengthening dollar, weak industrial data from China and expectations that members of the Organization of the Petroleum Exporting Countries won’t cut output at their meeting, kept oil prices on downtrend. Later, brief respite to falling prices largely on expectations of a possible cut in oil production from the Organization of the Petroleum Exporting Countries (OPEC) was quickly whisked away as OPEC contrary to expectations agreed to keep pumping crude at current production levels despite a global glut. Further, despite release of first decline in US crude supplies in 11 weeks, oil prices continued to decline as OPEC’s decision to continue current level of oil production quashed any hopes of improving the current oil glut situation.

Offshore World | 55 | December 2015 - January 2016

www.oswindia.com

FEATURES

Subsequently, data from the Organization of the Petroleum Countries’ report showing that the group increased its crude production in November to its highest monthly level in three years and the International Energy Agency warning that the global crude-supply glut will continue to pressure prices next year added to the downward pressure on crude oil prices. Further, barring few sessions, oil prices continued its south-bound journey helped by jump in weekly released US oil stock levels and the announcement by US Federal Reserve to hike its first interest-rate in about a decade. Later, with data release showing rise in number of active US oil rigs, NYMEX crude oil futures, registered its two-month-low of USD 33.98 on December 21. Oil prices then got some boost by the US government’s decision to reverse a 40-year export ban on US crude. Later, weekly released data revealing that US crude oil inventories posted an unexpectedly large decline added to the recovery in oil prices. A few spells of winter storms and forecasts for colder weather in US also provided some support to oil prices. However concerns over global crude glut amidst worries over slackening oil demand as well as Saudi’s vow of being ready to meet any increase in global oil demand kept pressure on oil prices. Finally, NYMEX crude oil futures closed the two-month period at USD 37.04 down by 20.5 per cent in two-month period. Like crude oil, futures prices of oil derivates such as heating oil and gasoline (both traded on NYMEX-CME platform) also moved down in the two-month period of November-December 2015. While, NYMEX gasoline futures prices declined by 9.8 per cent; NYMEX heating oil futures prices plummeted by 26.6 per cent with relatively mild winter weather conditions in US for major part of the period. The other major energy commodity, NYMEX natural gas futures prices managed to move up by a paltry 0.7 per cent in the two-month period of November-December, with a close at USD 2.337 per mmBtu. In early part of two-month period, gas prices slid on concerns over a supply glut amidst warmer temperatures in the US Later, gas prices recovered as www.oswindia.com

forecasts of a colder weather in US boosted expectations of an increasing demand. Moreover, a consistent fall in the weekly gas inventory data of the US for December aided the rise in prices. Like other energy commodities, ICE Rotterdam monthly coal futures prices also moved down by 9.5 per cent in the two-month period of November and December. Slowing economic growth in China and transforming environmental policies worldwide — including the climate agreement in Paris on December 12, wherein one hundred and ninety five countries signed a new climate deal which aims to reduce reliance on fossil fuels, pulled coal prices lower. Finally in the emission segment, falling energy prices especially of coal and weak auction demand led EUA futures traded on the ICE platform fell by 4.5 per cent in the two-month period of November-December. (Authors are Managers with Multi Commodity Exchange of India Ltd, Mumbai Views expressed here are personal.)

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 | 56 | December 2015 - January 2016

Special Offer Grab

55% upto

Limited Special Discount offer on subscription of Offshore World

India’s premier bi-monthly magazine providing insights into Upstream, Midstream & Downstream Hydrocarbon Industry, which is now into its 12 th year of publication is presenting a special offer for its readers & subscriber. Upcoming Issue of Offshore World: February-March 2016 - Advancements in Oil & Gas Industry

Sr. No.

Period Of Subscription

Yearly Subscription (in `)

% Discount

Amount to be paid Amount You Save (in `) (in `)

1 Year

900

25%

675

225

2 Year

1800

40%

1080

720

3 Year

2700

55%

1215

1485

Please Tick the box

Offer Valid till 30 th January’16 only Please fill up the contact details First Name ......................................................................................................................... Last Name ............................................................................................. Firm Name ......................................................................................................................... Email ...................................................................................................... Mailing Address ................................................................................................................................................................................................................................. ............................................................................................................................................................................................................................................................... City ......................................................................................................................................State ....................................................................................................... Pin Code ............................................................................................................................ Contact Number .................................................................................. Please send your cheque in favour of “ JASUBHAI MEDIA PVT LTD ” payable at Mumbai. Add ` 50/- for outstation cheques. All the above complete field along with cheque should reach us at: FOR BANK TRANSFER Beneficiary: JASUBHAI MEDIA PVT.LTD Bank: HDFC Bank Ltd Branch: Marine Drive Address: 143, Ground Floor, Soona Mahal, Marine Drive, Mumbai-400021 Bank Account No.: 12122020002057 IFSC Code (NEFT/RTGS): HDFC0001207 Swift Code(Iternational Remittance): HDFCINBB All the above complete field along with cheque should reach us at: Jasubhai Media, Subscription Dept, 3 rd Floor, Taj Building, 210 Dr D N Road, Fort, Mumbai-400001. Tel: 022-4037 3636

MARKETING INITIATIVE

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

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

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

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

Offshore World | 58 | December 2015 - January 2016

MARKETING INITIATIVE

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

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

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

For more information visit www.flir.com The images displayed may not be representative of the actual resolution of the camera shown. Images for illustrative purposes only. Offshore World | 59 | December 2015 - January 2016

www.oswindia.com

MARKETING INITIATIVE

WAFER-CONE® FLOW METER

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

ngineers with small line size processes rely on the versatile Wafer-Cone Flow Meter for superior accuracy and repeatability. The space-saving unit is easy to install. It’s ideal for tight-space installations and retrofits. It requires almost no maintenance. The Wafer-Cone further reduces life-cycle costs with a long life. The Wafer-Cone flow meter uses the same revolutionary principles as the V-Cone. Its self-conditioning means little or no upstream or downstream piping runs are required. The Wafer-Cone features a flangeless design. The element is easily replaced to accommodate changing flow conditions. Recalibration is not required. There are no moving parts to maintain. The unit combines exceptional flexibility with high performance. The Wafer-Cone is the perfect low-cost solution to tough flow measurement problems in water & waste water, chemical, food & beverage, plastics, pharmaceuticals, district HVAC, textile, power and oil / gas production. Applications The flangeless Wafer-Cone® is compact, less costly and easy to install. The cone conditions the flow so the Wafer-Cone requires minimal upstream or downstream pipe runs and can be installed virtually anywhere in a piping system. Ideal for small line sizes and with no moving parts, no replacement parts or scheduled maintenance, this meter offers a low cost of ownership and long life. Applications : • Natural Gas Wellheads • Gas, Water and CO2 • Injection • Gas Lift • Fuel Gas • Sepator Discharge • Biogas Reactors • Cooling Systems

www.oswindia.com

• Plant HVAC • Process Gas Lines and More ... Key Features: Unlike an orifice plate, the Wafer-Cone has no sharp edges so extensive maintenance and inspection are not required • No straight pipe runs • Maximum flexibility • Economical • Accuracy to +/- 1% • Repeatability to 0.1% • Machinable in any material • No moving parts, low maintenance How It Works The Wafer-Cone works on the same operating principle as the V-Cone. It is a differential pressure type flow meter with a unique design that conditions the flow prior to measurement. • Differential pressure is created by a cone placed in the center of the pipe. • The cone is shaped so that it “flattens” the fluid velocity profile in the pipe, creating a more stable signal across wide flow downturns. • Flow rate is calculated by measuring the difference between the pressure upstream of the cone at the meter wall and the pressure downstream of the cone through its center. For more information visit Toshniwal Hyvac Pvt Ltd 267,Kilpauk Garden Road,Chennai - 600010 Contact : +91 44 26445626 /8983 Email : sales@toshniwal.net Web: www.toshniwal.net

Offshore World | 60 | December 2015 - January 2016

MARKETING INITIATIVE

ASKO OIL & GAS ENTERPRISES

t’s Time to Transform Your OTS from a Training Tool to a Learning Tool We Own Expertise in OTS services

Distillation Series Flash Tank | Unit Operations of Chemical Processing | Distillation | Reboiler | Ethanol Distillation

Is there any ambiguity on following questions? • Are you looking forward to order OTS for training? • Are you sure you ordered OTS from training point of view? • Is the OTS built from training point of view? • Are you able to achieve satisfactory efficiency in OTS training? • Are you able to achieve knowledge retention using OTS? • Has your OTS transformed from a training tool to a learning tool? • Make a OTS Training Blue Print… Develop it…Use it….Transform it……….

Our Services: • OTS Consultation • Supply Generic and customized training simulators / OTS for LNG, Oil & Gas, Chemical & petro chemicals, Refineries, Energy, Pharmaceuticals • Train The Trainer Programme • Renting OTS for training

Readily Available Simulators

The Journey………………………

Note: All above simulators comes with Performance evaluator, Process exercise library, and training workbooks

Roles in OTS projects: Control Room Operator (CRO) trainer | Process Trainer Train colleagues on tool and process | Updating delivered OTS model from training point of view | Prepare assessment for CRO | Dynamic modeling and steady state evaluation of models for OTS | Prepare technical bidding proposals | Been part of technical sales team in India | Preparing OTS graphics and updation | Prepare sequence for turbines & anti-surge systems modeling (consimaps) | Detector placement for fire and gas systems | DCS integration | To trouble shoot difference in parameters between delivered OTS and real plant values and rectify it | Assist in preparation of FDS for OTS. For more information visit Hussain A Tinwala Email: hussain@asko-oilngas.com Website: www.asko-oilngas.com Contact: +91 9867369372

Offshore World | 61 | December 2015 - January 2016

www.oswindia.com

PROJECT UPDATE

Media Barter with gulfoilandgas.com

Projects Database Petrochemical Plants and ReďŹ neries Major Projects in the Middle East, Africa and Caspian Sea

Project

Country

Value ($)

Status

Middle East Bahrain Aromatics Plant

Bahrain

Sitra Refinery Expansion Project

Bahrain

Baiji Oil Refinery

Iraq

Study 9,000,000,000

Bidding Execution

Bazian Refinery Expansion Phase 3

Iraq

500,000,000

Bidding

Karbala Refinery

Iraq

6,040,000,000

Execution

Lukoil- New Petrochemicals Plant

Iraq

AI-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

Study

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 !so-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

IPIC- New Fujairah Oil Refinery

UAE

3,500,000,000

Bidding

Ruwais Refinery Expansion (RRE)

UAE

10,000,000,000

Execution

Value ($)

FEED

Africa

Country

Sonatrach - Paraxylene Crystallization Plant

Algeria

Tiaret Oil Refinery

Algeria

6,000,000,000

Execution

Lobito (SonaRef ) Refinery

Angola

8,000,000,000

Execution

Soyo Refinery

Angola

www.oswindia.com

Status Study

Offshore World | 62 | December 2015- January 2016

Study

PROJECT UPDATE Cameroon Ammonia Urea Fertilizer Plant

Cameroon

1,400,000

Study

Cameroon Atlantic Refinery

Cameroon

Assiut Refinery Expansion

Egypt

135,000,000

Execution

Study

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

17,000,000

Execution

Equatorial Guinea Fertilizer

Guinea

Kenya Petroleum Refineries Limited (KPRL) Mombasa Refinery

Kenya

Study

Mellitah Complex

Libya

Mohammedia Refinery Rehabilitation & Expansion

Morocco

816,000,000

Execution

lbeno 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

Execution

Study

Hoima Oil Refinery

Uganda

2,500,000,000

Execution

Caspian Region

Country

Value ($)

Status

Baku Heydar Aliyev (Azerneftyanajag) Refinery Upgrade

Azerbaijan

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

FEED

Execution

Kavian Petrochemical Complex (Oiefins 11)

Iran

Kharg Oil Terminal

Iran

942,000,000

Execution

Completed

Lorestan Petrochemical Complex

Iran

Execution

Mahabad Petrochemical Complex

Iran

Execution

Morvarid Petrochemical (5th 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

Far Eastern Petrochemical Company Construction (FEPCO) Projec1 Russia

Execution 5,000,000,000

Study

Moscow Refinery Upgrade

Russia

Execution

Nizhegorodnefteorgsyntez Refinery Upgrade

Russia

Ufa Refinery Upgrade

Russia

Completed

Yaro-Yakhinskoye Field

Russia

Execution

1,698,600,000

Offshore World | 63 | December 2015- January 2016

Execution

www.oswindia.com

 

                            

PRODUCTS

                  

SCRAPPER MECHANISM FILTERS

               

 

o  Scrapper mechanism self-cleaning filters are widely  used for continuous filtration requirement without any  replacemento of filter consumables and without exposure of operators. Like auto backwash filter, scrapper mechanism  self-cleaning  is used for preliminary filtration following  the same oprinciple of differential pressure; the only  difference is that it is used for applications where back   washing medium is not available. Scrapper mechanism  self-cleaning filter is used wherein one cannot introduce  o  any additional substance for back washing. The filtration  process becomes smooth because of automatic continuous  on-line filtration. The gear motor runs against the spring  o  actuated scraper and the concentrated solids are drained   off by the system, thereby keeping the function of the   cartridge well. PLC control function means differential pressure cleaning,   scheduling of cleaning process and manual cleaning. The differential-pressure  is an important parameter for operation and can be connected with the central   control room. Validated by practice, this filtration process is highly effective and  using the wedge cartridge, it can be easily cleaned with less abrasion. In many   fields, this filter can replace the traditional filters like sand filters, filter press, etc. 

For details contact: Filter Concept Pvt Ltd 302, Aalin, B/h Jet Airways Office, Ashram Road, Ahmedabad, Gujarat 380 014 Tel: 079-27541602, Fax: 91-079-27540801 E-mail: info@filter-concept.com

INTELLIGENT AUTOCAD-BASED 3D PLANT DESIGN SOLUTION Intergraph Process, Power & Marine (PP&M), part of Hexagon offers CADWorx 2016, an AutoCAD-based intelligent 2D and 3D plant design system, features significant enhancements including capabilities for greater control of material assignment at the specification level, management of all specification content across all versions, the ability to facilitate the use of highly specialized components with combination of different end-types and much more. Intergraph CADWorx & Analysis Solutions’ offerings allow design and engineering to share relevant information seamlessly, thereby maintaining accuracy and improving efficiency. These include CADWorx Plant Design Suite, for AutoCAD-based intelligent plant design modeling, process schematics and automatic production of plant design deliverables; CADWorx DraftPro, a free solution for intelligent 2D design and layout; CAESAR II, the world’s most widely used pipe stress analysis software; PV Elite, for vessel and exchanger design and analysis; TANK, for the design and analysis of oil storage tanks; GT STRUDL, one of the most trusted, adaptable and fully-integrated structural analysis solutions in the world; and Visual Vessel Design, a comprehensive pressure vessel, shell and tube exchanger, and boiler design and analysis solution. For details contact: Intergraph Corp 19 Interpro Road, Madison, AL 35758, U.S.A. E-mail: jerry.felts@intergraph.com www.oswindia.com

EXPLOSION-PROOF IR THERMOMETER (PYROMETER) LumaSense Technologies, Inc offers its next generation petrochemical IR sensor, the PULSAR 4 for optimization of sulphur recovery processes. The PULSAR 4 is LumaSense’s latest addition to its E2T line of petrochemical IR sensors. Oil and gas operations are heavily dependent on combustion-based processes to supply the world’s growing energy needs. The PULSAR 4 is intended for monitoring the refractory and gas temperatures inside sulphur recovery units, sulphur burner furnaces, and thermal oxidizer furnaces frequently found at these facilities. The PULSAR 4 is an explosion-proof IR thermometer (pyrometer) with the ability to see through flames and simultaneously deliver the refractory temperature and gas temperature with precision to 0.3°C and a range of 350°C to 2,000°C. The PULSAR 4 Advanced features LumaSense’s propriety Smart Flame Measurement Algorithm (Smart FMA) which accounts for flame transparency that can affect the temperature readings for a more precise view of activity inside these vessels. LumaSense’s updated and powerful InfraWin software interprets the data from the PULSAR 4 for analysis inside control room. Customers with PULSAR II and III can leverage their existing infrastructure to upgrade these units to the new PULSAR 4 and its advanced capabilities. For details contact: LumaSense Technologies GmbH Kleyerstraße 90, Frankfurt / Main, 60326 Deutschland, Germany Tel: +49 (69) 97373198, Fax: +49 69 973 73-167 E-mail: s.schiepe@lumasenseinc.com

SOLUTIONS FOR DECK MACHINERY Several applications like mooring and tugger winches, anchor handling systems, traction and storage winches, capstans and windlasses offer a bench test for the 700C Series in medium-light power cases, and HDP/HDO Series in medium-high power cases. The 300 Series and 700T Series are used for pinion ring transmission systems. The winch drum is generally supported on the opposite side of the gearbox, but strong bearings in the 700C Series enables it to have a console set-up as well. Hydraulic and electric driven variations, as well as in-line or right angled configurations, are available throughout the Bonfiglioli range. For details contact: Bonfiglioli Riduttori Spa Via Giovanni XXIII 7/a 40012 Lippo di Calderara di Reno Bologna, Italy Tel: +39 051 647 3932 E-mail: MariaCristina.Venturoli@bonfiglioli.com / ameet.rele@bonfiglioli.com

Offshore World | 64 | December 2015 - January 2016

LPG STORAGE TANKS Mellcon offers multiple LPG storage tanks, LPG-mounded bullets and systems in range of sizes to suit the requirements of the customer on turnkey basis duly approved by the Chief Controller of Explosives as per SMPV Rules. The two main forms of LPG are commercial butane and commercial propane. LPG may be liquefied by moderately increasing the pressure or by reducing the temperature. Refrigerated storage is used by gas suppliers to store large volumes of LPG. The main form of LPG storage is in special tanks known as pressure tanks. Commonly, these pressure tanks are termed bulk tanks or LPG bullets, because LPG has a high coefficient of expansion in its liquid phase, the tanks are never completely filled with liquid (tanks are filled to approx 85% of their water capacity), the remaining space being taken up with vapour (often referred to as the vapour space) to facilitate expansion without allowing the liquid to become 100% full (often known as hydraulically full). These are designed as per the recommendations in IS-2825 / ASME Sec Vlll DlV - 1 Codes and the MoC are SA-516/IS-2062/IS-2002/SS-304 or as per the specific requirement of the customer. Steel used for the tank and its fittings meets the low temperature carbon steel criteria and is tested thoroughly before fabrication. During fabrication stringent quality norms are followed. Each tank undergoes various NDT and other inspection stages. For details contact: Mellcon Engineers Pvt Ltd B-297 Okhla Indl Area, Phase 1, New Delhi 110 020 Tel: 011-26811727, 26816103 Fax: 91-011-26816573 E-mail: mellcon@mellcon.com

RACK MONITOR OPW Engineered Systems offers RM140W rack monitor to its complete line of terminal solution offerings. Built for truck or rail loading in petro-chemical applications, the RM140W protects against overfills and continuously monitors the grounding connection, increasing safety at the point of transfer. In addition to being universally compatible, the RM140W meets or exceeds the requirements of multiple organizations as an explosion-proof device. This perfectly aligns with OPW Engineered Systems’ belief of fostering a safe and productive work environment. The RM140W rack monitor replaces the Opti-Therm 8500 Series. For details contact: Dover India Pvt Ltd – PSG 40 Poonamallee By-pass, Senneerkuppam, Chennai 600 056 Tel: 044-26271020, 25271023 E-mail: sales.psgindia@psgdover.com

PRODUCTS INLINE PROCESS MONITORING IN HYDROFLUORIC ACID ALKYLATION UNITS SensoTech, Germany and HF Alkylation Consultants, USA jointly developed the LiquiSonic 40 HF inline analyzer. The measuring system consists of two sensors and one controller. The sensors are installed directly into the existing main pipe of the alkylation unit and simultaneously measure in the process stream the hydrofluoric acid strength, the water content and the concentration of acid soluble oils. The measurement accuracy is ±0.05 wt% and the installation does not require a bypass. For the inline concentration measurement, a sonic velocity sensor and a density sensor are used, that are Ex-certified and made of corrosion resistant material (Hastelloy C276). The analyzer provides stable measurement results updated every second. The real-time information will be provided online to the process control system. The LiquiSonic controller visualizes and stores the data completely. Installing and operating the controller can take place in a safe area. Remote access options allow the operation from the laboratory or the PC at the workplace, for example. Via 4-20 mA, digital outputs, serial interfaces, fieldbus or Ethernet, the controller can be integrated into the network and process control system. With the inline concentration measurement directly in the process, engineers are able to recognize deviations from reference values immediately, and so countermeasures can be taken in time. Compared to alternative analytical techniques such as laboratory analysis or atline analyzers, the inline analysis provides better response times and higher safety standards. Furthermore, the LiquiSonic inline process analyzer involves lower investment costs and no risk of leakages in contrast to atline systems. For details contact: SensoTech GmbH Steinfeldstr 1, D-39179 Magdebure Barleben, Germany Tel: +49 39203 514100 Fax: +49 39203 514109 E-mail: info@sensotech.com

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

Offshore World | 65 | December 2015 - January 2016

www.oswindia.com

EVENTS DIARY

OSEA2016

CIPPE 2016

Date: March 29-31, 2016 Venue: Beijing, China Event: China International Petroleum & Petrochemical Technology and Equipment Exhibition (cippe) is a regular gathering in petroleum and petrochemical industry. With a magnificent exhibition space over 100,000 sqm, the 16th China International Petroleum & Petrochemical Technology and Equipment Exhibition, scheduled on March 29-31, 2016 in New China International Exhibition Center, will attract 2,000 exhibitors from 65 nations and regions, 18 international pavilions and 80,000 professional visitors. CIPPE Beijing 2015 welcomed the attendance of 15 national pavilions, including USA, Germany, UK, French, Canadian, Danish, Italian, Russian etc. In addition, the well-known global enterprises such as GE, Baker Hughes, National Oil Varco, 3M, Schneider, Honeywell, API, Caterpillar, Cummins, MTU, Tyco and Hempeletc all have participated in the event. Moreover, CIPPE Beijing 2015 received great support from the domestic oil giants such as CNPC Pavilion, Sinopec Oil Engineering Machinery Company, CNOOC, CSSC, CSIC, CIMC RAFFLES, RG Petro-machinery (Group) Co., Ltd., HONGHUA, YANTAI JEREH, KERUI, JUNMA, Shengli Oilfield Highland Petroleum, SHENKAI, HUABEI RONGSHENG, Tianjin LILIN and etc. For details contact: Donna Liang Beijing Zhenwei Exhibition Co., Ltd Tel: 8610-5823 6534 | 86-13911035943 E-mail:ldm@zhenweiexpo.com Website: http://www.cippe.com.cn/2016/en/

5 th East Africa Oil & Gas Expo 2016

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

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 Web: 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 | 66 | December 2015 - January 2016

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