Offshore World June-July 2018 by Offshore World

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OFFSHORE WORLD

INSIGHT INTO UPSTREAM & DOWNSTREAM HYDROCARBON INDUSTRY

JUNE-JULY 2018

Decommissioning

VOL. 15 ISSUE 4 MUMBAI US $ 10 ` 150

International Exhibition & Conference February 2020, Mumbai, India

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R.N.I. No. 39849/82. Date of Publication: 1 st of every alternate month

CONTENTS

EDITORIAL

Editor Editorial Advisory Board Design Team Subscription Team Production Team

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

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MARKETING TEAM & OFFICES

-Dr. Pranjal Kumar Phukan D.Litt. (Hons), Supply Chain expert Dibrugarh, Assam GP Global signs an agreement to produce Cepsa’s marine lubricants in India

The Middle East to India-Deepwater Pipeline

From operation to cessation of production: creating a smooth transition

Oil & Gas Pro: Rise in India’s LNG Imports, Driven by Increased Consumption

-Ashish Agrawal, Analyst, India Ratings and Research Private Limited -Vivek Jain, Director Marine Insurance

-Mr Amit Agarwal,Director, Ideal Insurance Brokers Pvt Ltd. Environmental Considerations in Decommissioning of Offshore Facilities

-J S Sharma,, Ph.D., STA Fellow (Environment), Japan, Former Group General Manager (Chem . ) - Head

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NEWS

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FEATURES

Decommissioning of Storage Tanks After Commissioning in Chemical Industry The term ‘decommissioning’ refers to the administrative and technical actions taken to allow the removal of some or all of the regulatory requirements from a facility. Oil and chemical tank removals pose major environmental and health and safety risks. In 2016 a major utility company and their subcontractor were fined over £900,000 after a poorly planned tank removal job led to a serious pollution incident. In this incident 300 litres of residual sodium hypochlorite was diluted with water and discharged to the storm drainage system killing virtually all aquatic organisms for a 1 mile stretch of river. If this residual liquid had been pumped out, the incident could have been avoided preventing a major pollution incident and a substantial fine for the companies involved. There is a high risk of pollution during the installation, decommissioning and removal of underground storage tank (UST) systems. This pollution prevention guidance covers all USTs, including those containing petroleum, diesel, fuel oil, aviation fuel, waste oil, domestic heating oil and other potentially polluting materials such as organic solvents. Leaking underground tanks can be responsible for significant soil and groundwater contamination. Underground storage tanks typically contain oils, fuels, and chemicals and other types of liquids. Damaged, corroded, or poorly installed systems, and poorly maintained caps, seals and spill boxes can lead to leakage of these contaminants. Decommissioning is increasingly becoming a major issue, since hundreds of facilities will end their operational lifetimes over the next decades. The decommissioning of oil and gas production facilities and their associated structures such as waste management and storage facilities gives rise to a variety of waste materials and items, some of which may be radioactive (e.g. sealed and unsealed sources, NORM scales, contaminated equipment, and concrete and soil). The decommissioning process involves numerous issues and activities including: • • • • •

Development of the decommissioning strategy and plan and associated QA programmes Development of dismantling and decontamination strategies; Assessment of risks to workers, the public and the environment during and after the decommissioning activities; Submissions to the regulator, e.g. plans, strategies, records, reports and survey results; Approval by the regulatory body;

Tank Decommissioning Regulations Given the potential risk to health and the environment, and the associated liability to property owners, removal of underground fuel storage tanks is highly regulated. The Technical Standards & Safety Authority (TSSA) regulates transportation, storage, handling and use of fuels to ensure conformance with the Technical Standards and Safety Act, 2000 (TSSA Act 2000). (Fig. 1) www.oswindia.com

Fuel storage tank removals must be completed by a qualified Licensed Petroleum Contractor whose personnel are licensed in compliance with the TSSA Act, 2000 and who work in accordance with applicable Regulations, Codes and Standards. Following removal of a fuel tank, an environmental assessment report must be completed in accordance with the requirements specified in the TSSA Fuels Safety Division Liquid Fuels Handling Code and “Environmental Protocols for Operating Fuel Handling Facilities in Ontario” and signed by a Qualified Person (e.g. Professional Engineer or Geoscientist). If contamination is discovered upon tank removal, remediation must be completed in accordance with O. Reg. 341 and O. Reg. 153. (a) A typical tank decommissioning project will include: • Site visit & planning the project We will conduct a site visit to assess the condition, specification and contents of the redundant tanks and ascertain if there are any site restrictions which would impact on the safe and timely removal of the tanks. Removing a tank can cause operational concerns for the site so it is essential a thorough assessment is undertaken to prevent any unnecessary delays. Before commencing any work the client will be issued with a thorough Risk Assessment & Method Statement to ensure they are satisfied that the project has been planned appropriately. • Sampling residual liquids In order to ensure health and safety is prioritized during the project and that the disposal method of any residual liquids is legally compliant and the most cost effective option a sample of the contents will usually be taken and sent to laboratory for analysis. In many cases residual liquids (usually oils) will hold commercial value which can be offset against the cost of the project. In some cases whole tank decommissioning projects can be completed on a cost neutral basis due to the commercial value of the oil. Unfortunately tanks are often left redundant for years before they are decommissioned which can allow the product to develop impurities which lower its commercial value.

Fig. 1: Tank decommissioning

Offshore World | 6 | June-July 2018

• Isolation and waste removal All residual liquids will be drained and/or pumped out and disposed of correctly. Any residues which cannot be drained will be removed mechanically by a vacuum tanker or where necessary manually by a confined space entry

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FEATURES the tank will be removed intact and dismantled at a more practical location. (Fig. 3) • Tank Removal & Disposal Once safe to do so the tanks will be removed via a crane/Hiab and transported under our upper tier hazardous waste license to a licensed waste facility for disposal. (Fig. 4)

Fig. 3: Tank cutting process

• Decontamination and removal of associated infrastructure This can include removal/capping of pipework and decontamination of plinths and bunds often to a level where they can be disposed of as inert waste.

Fig 2: Isolation of storage tank and breathing apparatus trained team. Confined Space Entry teams will be equipped with a gas detector to warn them of any dangerous e.g. explosive atmospheres. (Fig 2) • Decontamination of tanks The tanks will be thoroughly cleaned to remove all hazardous residues, for steel tanks this will allow them to be recycled as scrap metal which will again have a commercial value to the client. Cleaning can be undertaken using water, a suitable degreaser or using steam. Cleaning can be undertaken in situ or at a licensed site after removal. • Purging If a tank is to be entered or hot works to be conducted the tank will require purging (the removal of flammable gases or vapors) or made inert before these works can commence. • Tank Cutting/Dismantling If access issues make it unsafe or uneconomical to remove the tank intact the tank can be dismantled in situ using hot and cold cutting techniques. Ideally

• Contaminated Land Testing & Remediation Where tanks have potentially caused contamination to the surrounding land we can undertake a Site Investigation to establish any contamination and can undertake remediation works to remove any contamination which is discovered. Specific industries and different sizes and types of tank have specific guidance on how to decommission them. GPT structure every tank decommissioning project to follow the relevant legislation and best practice guidance that applies to the specific tank. USTs are decommissioned on either a permanent or a temporary basis. Many tanks are temporarily decommissioned and then forgotten about. To avoid the risk of pollution, the Agencies recommend removal of tanks that are unlikely to be used again. The Blue Book contains comprehensive technical guidance on the decommissioning of USTs. Although it refers to the storage of fuels, the advice is often applicable to other products stored underground. Operators are particularly advised to refer to the Blue Book for information about the health and safety issues associated with decommissioning USTs. The Agencies are particularly concerned about the removal and disposal of the remaining product in the tanks and pipelines. All product and tank bottoms must be removed and disposed off correctly. Once this has been carried out, the risk of pollution is much less, as the pollution matter has been removed. The operator must also ensure that there is no residual contamination of the site such as petrol contamination of the soil and groundwater.

Dr. Pranjal Kumar Phukan D.Litt. (Hons) Supply Chain expert Dibrugarh, Assam Email: pranjal_xlri@yahoo.com

Fig. 4: Tank removal www.oswindia.com

Offshore World | 8 | June-July 2018

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FEATURES

GP Global Signs an Agreement to Produce Cepsa’s Marine Lubricants in India To expand their footprint into marine business, GP Global Energy Private Limited, India had entered into an exclusive partnership with Cepsa to make and market Cepsa’s marine and power generation lubricants in India.

P Global Energy Private Limited (GPGEPL), part of UAE-based global conglomerate GP Global, entered into an exclusive partnership with Cepsa, the integrated Spanish oil major, to produce and market Cepsa’s marine and power generation lubricants in India. As per the agreement, GP Global will manufacture, blend, package as well as import Cepsa branded lubricant products in India. “In recent years, India has experienced huge growth in ports modernization and coastal shipping development programs, which have been supported by our government. The partnership with CEPSA reinforces GP Global’s contribution towards the ‘Make in India’ initiative. With these developments, we have seen a renewed vibrancy in our industry, which has resurged growth once more. Cepsa is a well reputed international brand and will be a good fit for our portfolio.” said Mr. M Prabakaran, Global Head of Terminals & Country Head, GP Global Group, India.

from natural sources, and has a renewables business. The Company has over 85 years of experience and a team of close to 10,000 professionals. Cepsa has a diversified portfolio of lubricants, base oils and paraffin waxes, which it has marketed in over 80 countries since 1950 with a specialized sales team. Currently is one of the leading companies in manufacturing and selling finished lubricants and base oils in Spain and exports products to Europe and other expanding markets, such as Latin America, Middle East and North Africa and Asia. It has two specialized lubricants plants in Spain, in San Roque (Cadiz) and Paterna (Valencia), which also produces hi- tech coolants. GP GLOBAL Group is a leading player in the oil industry with a vision to be an integrated multinational energy organization, driving growth with development projects spread across different continents. GP Global (previousluy Gulf Petrochem) has firmly established itself into strategic business units; Refining, Storage terminals, Trading and Bunkering, Bitumen Manufacturing, Lubricant and Grease Manufacturing, Shipping and Logistics.

“This partnership will strengthen Cepsa’s international brand and the expansion of our lubricant business, this will be the first time our lubricants will be produced outside our plants in Spain, as the facility in Mumbai has been the first approved by us after a rigorous and successful audit process. GP Global complies with our highest standards requirements, occupies a strong position in the Indian maritime industry, and has in-depth know-how of the lubricant and bunkering businesses” said Mr. Álvaro Díaz Bild, Vice President – Marketing, Cepsa.

GP GLOBAL operates as a physical supplier as well as provider of Bunkers at Worldwide ports. They are currently supplying physical bunkers in Fujairah, Khor Fakkan, Singapore, Rotterdam and also other UAE ports through our own bunker barge in port and at sea. Across the Indian coastline they are present as physical supplier as well as Bunker traders’ catering to needs of various clients from across the globe. They are the most prominent bunker suppliers across all Major and Minor Ports of India.

“Cepsa marine and power generation lubricants, as well as the wide Cepsa’s lubricants portfolio, are currently exported from Spain to different countries. The partnership with GP Global will provide the necessary framework to enter into the Indian market as the company has wide experience in the marine market, especially in bunkering” said Mr. Carlos Giner, Director of Lubricants, Base Oils and Paraffin Waxes, Cepsa.

To expand their footprint into marine business, GP Global Energy Private Limited, India had entered into an exclusive partnership with Cepsa to make and market Cepsa’s marine and power generation lubricants in India.

This partnership will also strengthen the in-house R&D facilities at GP Global and develop technologically advanced products in India. The product range includes Cylinder Oils, System Oils, Trunk Piston Engine Oils, Hydraulic Oil, Gear oils, Greases and other specialty lubricants required by the industry. Cepsa marine range of products include Cepsa Larus, Gavia, Ciconia and Petrel lubricants, among others.

GP Global Energy will be manufacturing the Marine lubricants through a contract with its group company GP Petroleums Limited in their plant at Vasai, Mumbai, which is already engaged in blending Automotive and Industrial lubricants over the last four decades. The plant has state of the art R&D and QC facility for product development and consistency. The plant is certified with ISO 9001, ISO 14000 and OHSAS 18001.

Cepsa is a global energy company with integrated operations across the entire hydrocarbon value chain, manufactures raw materials for the chemicals industry

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Offshore World | 10 | June-July 2018

M. Prabhak aran Global Head of Terminals & Countr y Head – GP Global Group, India

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Pipelines

APRIL-MAY 2018

Offshore World is an all-encompassing magazine for the hydrocarbon and allied industries. The magazine extensively covers technological advances, reviews & forecasts, new products, processes & solutions, upcoming projects, market trends, R&D, events, products review, book review, industry surveys, environment management, news & views, interviews, awards, outstanding performance by individuals & organizations, case studies & practice oriented and well researched articles and features by industry experts.

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FEATURES

The Middle East to India-Deepwater Pipeline MEIDP 1 will be the first in a series of pipelines supplying gas to the Gujarat coast of India, from the vast available resources in the Middle east, by the safest, most economic and reliable means The MEIDP Project is envisaged as transmission pipeline Infrastructure project allowing transportation of Middle East Gas to the West Coast of India

Key Highlights of Pipeline and LNG Particulars

Pipeline

LNG

The pipeline will be laid as a “Common Carrier” pipeline whereby SAGE will be the Gas Transporter and will be paid a Tariff for pipeline use

Constant Supply

Yes

Gas Source

Fi xe d s o u rce a n d Flexibilit y to source gas from destination for gas various sources

The Gas Buyers and the Gas seller will negotiate the Long Term Gas Supply Contract themselves [under the aegis of SAGE in a Tri-partite Framework Agreement]

L o n g T e r m Yes Commitment

MEIDP 1 will be the first in a series of pipelines supplying gas to the Gujarat coast of India, from the vast available resources in the Middle east, by the safest, most economic and reliable means Iran - India’s Gas Partner India needs gas • Over 2,000 TCF of natural gas reserves are held by countries with which India has a traditional trading relationship i.e Iran, Qatar and Turkmenistan. • Iran has over 1000 TCF reserves and is eager to export gas. • The deepwater route across the Arabian Sea is the shortest secure d i s t a n c e b e t we e n h u g e m i d d l e e a s t re s e r ve s a n d t h e r a p i d l y developing industrial heartland of India, and is too short for LNG to be an economic transportation option

Possible to source Long Term and Spot Cargoes

Cost of Construction

Dependent on distance, Dependent only on capacity capacity and depth – relatively independent of distance

Operating Cost

Only transportation Transportation tariff, Liquefaction tariff applies charges Regas charges

Maintenance Cost

Minimal

Periodic maintenance required

Iran has gas • Iran has always been a friendly neighbour to India • Iran has expressed its willingness to supply Natural Gas and a Framework Agreement has been discussed with NIGEC [Now NIOC Gas Export Division] for Pipeline Construction and Gas Supply through the SAGE Pipeline • In 2015 NIGEC confirmed to SAGE that they are currently in a position to provide gas for 2 pipelines from Iran to India

Iran CCS Iran

CCS

India

India GPRT GPRT

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Offshore World | 12 | June-July 2018

Middle EasttotoIndia IndiaDeepwater Deepwater Pipeline TheThe Middle East Pipeline

Offshore World is an all-encompassing magazine for the hydrocarbon and allied industries. A bi-monthly magazine, launched in December 2003, Offshore World disseminates authen c, cri cal and well-researched informa on on global hydrocarbon industry innova ons. The magazine offers latest and strategic informa on on the upstream and downstream hydrocarbon industry. The endeavour of Offshore World is to become a vehicle in making “Hydrocarbon Vision 2025” a reality in terms of technologies, markets and new direc ons, and to stand as a medium of reflec on of the achievements and aspira ons of Indian hydrocarbon industry. Circula on: 25,370

OSW Target Segments

OSW Reader’s Proﬁle

5% Hydrocarbon Explora on 10% Hydrocarbon Processing 20% Drilling and Equipment Manufacturers 10% Development and Produc on Companies 13% Transporta on and Logis cs Companies 12% Reﬁning and Marke ng Companies 15% Plant, Machinery and Equipment Providers 10% Technology Solu on and Service Providers 5% Safety , Health and Environment

12%

13%

• CEOs & Senior Management of Oil Companies • Petroleum Engineers & Reﬁneries Contractors • Project Managers • Reﬁning & Pipeline Engineers • Corrosion Control Engineers • Opera ons Managers • Technical Managers • Safety Managers & Engineers • Purchase Managers • Marke ng Execu ves • Pollu on Control Specialists • R&D Personnel • Industry Consultants • Engineering & EPC Consultants • Indian & Overseas Industry • Associa ons • Training Ins tutes

15% 10% 30%

10% 5%

20% 5% 10% Hydrocarbon Exploration Hydrocarbon Processing Drilling and Equipment Manufacturers Development and Production Companies Transportation and Logistics Companies

Refining and Marketing Companies Plant, Machinery and Equipment Providers Technology Solution and Service Providers Safety, Health and Environment

OSW Region-wise Presence 53% Western Region [including Mumbai,Gujarat, Pune, etc] 23% Northern Region [including Delhi, UP, etc] 10% Southern Region [including Bangalore, Hyderabad, Chennai, Coimbatore, etc] 9% Eastern Region [including Kolkata, Assam, etc] 5% Interna onal [includes USA, MiddleEast, Russia, Brazil, Iran, China, Germany, Italy, France, etc]

FEATURES

From Operation to Cessation of Production: Creating A Smooth Transition If the industry is able to exploit the most optimum ways to increase the level of hydrocarbons that are economically recoverable, it can concentrate on value generating activities. Few would argue that spending capital unnecessarily on decommissioning is better.

he global oil and gas industry is in unchartered waters, with challenges including low oil price, high operating costs and ageing assets rivalling its pioneering production days half a century ago.

models of working, coupled with rigorous asset management, will help at a stage that demands a relentless focus on production optimisation, operational efficiency and cost reduction.

Decommissioning is never far from the headlines. Across the UK Continental Shelf (UKCS) for example, the industry is now plugging and abandoning more wells than it is drilling for exploration and appraisal. According to McKinsey & Company, 27 UK fields ceased production over the past five years to 2015, with a third of them approaching the regulator for approval to decommission. The number of wells plugged and abandoned in the UK more than tripled in the past three years.

Getting these factors right are fundamental if the industry is to unlock the remaining potential, safely and profitably. Production gains of assets at late life are potentially considerable. The Wood Review estimates there are

Based on current crude oil prices, analytics’ consultancy Wood Mackenzie sees a ramp up of decommissioning activities up to the early 2020s that is perhaps greater than ever previously forecast. Estimates are exactly that, but there is no denying the sheer scale of the issue. The challenge on the horizon is significant: decommissioning will be expensive and span several decades. And, added to this is a significant factor where infrastructure integrated and shared between installations can increase the complexity of decommissioning. Internationally, new rules are being introduced to accelerate decommissioning activity. More than half of the assets in Malaysian waters are more than 20 years old. Three Operators in this region have faced a decommissioning backlog. Only an estimated 95 platforms having been decommissioned since 1975, attributed to a lack of clear and specific regulations from national authorities. In comparison, The Gulf of Mexico dominates global decommissioning activity, with an estimated 4,600 offshore facilities decommissioned to date. Life before decommissioning What to do in late-field life is equally as pressing as decommissioning, and as worthy of the headlines. Following on from the key recommendations in the UKCS Maximising Recovery Review, led by Sir Ian Wood for national government, the OGA has set out its strategy to collaborate with industry to Maximise Economic Recovery (MER). Moving to late-field life is a tough decision to take for any operator, but it can mean more than entering ‘lighthouse mode’ to delay decommissioning liabilities. Radically leaner www.oswindia.com

between 12 and 24 billion barrels of oil yet to be recovered from the North Sea. The opportunity to generate significant value is echoed by McKinsey & Company, particularly over the next two decades. The firm puts the case for excellence in this transformative phase, highlighting that few companies as yet have truly positioned themselves to capture this value. If the industry is able to exploit the most optimum ways to increase the level of hydrocarbons that are economically recoverable, it can concentrate on value generating activities. Few would argue that spending capital unnecessarily on decommissioning is better. Reassessing what is required in late-field life Given the challenging market conditions, the need to improve operational efficiency and performance escalates in later life, to a point where every possible advantage matters. Activities that fail to deliver commercially or ensure safety standards are met, have to be eliminated. The challenges are complex during this phase, but the equation is simple: the leaner operations can become, the longer the length of profitable production. Reassessing requirements in late-field life shows where costs can be drastically reduced to remain profitable. What is important at the beginning of a field’s life changes as it reaches maturity. Initial efforts focus on maximising hydrocarbon recovery through longterm development plans. There are numerous technical tasks to perform. Dedicated technical specialists undertake studies in areas that include seismic interpretation, geological modelling, petrophysical evaluation, reservoir modelling, well modelling, system modelling and production optimisation. At the end of a field’s life, par ticularly when approaching CoP, the management of day-to-day production and operations takes precedence.

Offshore World | 14 | June-July 2018

FEATURES With remaining opportunities available, but perhaps not economically feasible to execute, many of the geoscience and reservoir engineering tasks become less valuable or simply not required. Outsourcing to lighten the burden The approach to outsource the full running of late-life assets offers a number of advantages, without detracting from the operator’s responsibilities for the assets approaching CoP. Fields can be optimised until abandonment, with minimum capital expenditure. Operating costs can be reduced significantly, with personnel redeployed to greater use elsewhere. At the same time, data can be gathered that is required for CoP and, in turn, decommissioning. Such an outsourcing approach is relatively novel and a bold strategic step for an operator and their joint venture partners. Getting the handover right for a smooth transition is critical, ensuring operations are safe while maximising profitability. How is this best achieved? And what competitive edge is possible when pushing the potential of such a model? Setting the agenda A late-field outsourcing approach should focus on six core objectives: • zero accidents and no harm to the environment • a cashflow positive position in the current marketplace • a competitive unit operating cost • extended field life where possible, deferring CoP and delaying decommissioning liabilities • preparing for CoP, while managing late-life assets • optimising well and reservoir performance. Running it down: a period of continuous improvement For as long as there is life in a field, the goal must be operations excellence. An outsourcing approach should be able to move quickly and efficiently from providing the essential service an operator requires to managing the assets through continual improvement. Superior asset performance and technically excellent subsurface operations pre CoP can start to be realised once the significant risks are identified and mitigated and the operator’s basic requirements, including compliance demands, are being met. Getting the framework right Handover of late-field life management should involve five main stages or sets of activities. Project framing and review Close collaboration with the client’s asset and operations teams is critical, gaining a total understanding of the planned scope of work, overall objectives during the transition period and the operator’s way of working, with special emphasis on aligned HSE cultures. Governance structure, accountabilities, reporting interfaces, deliverables, timelines and IT requirements should all be covered off.



Access to data and systems Effective transition is only possible with the operator’s systems to hand. IT solutions are readily available to provide the specialist contractor with



remote access to key information. This includes real-time production and injection well data, process and operations data, as well as the operator’s systems such as loss management, dashboards and intranet document management. Knowledge transfer Prior to handover, the full range of petroleum and reservoir engineering activities needs to be discussed through visits, meetings and in-depth reviews. Close cooperation is required on a daily, weekly, monthly, quarterly, annual and ad hoc basis to cover the range of requirements and responsibilities.



Management of meetings It is important to agree, refine and schedule the full inventory of meetings, with appropriate terms of reference. Meetings should involve both internal and external stakeholders, including joint venture partners and regulatory bodies, where applicable.



Quality control, peer review and project management In this final step, the transition plan is completed and agreed. Details on the peer reviews and quality control of the contracted service should be finalised. As a guide to timeframes, full management can be handed over by the operator to a specialist external team within a four-month, fully collaborative transition period.



Rethinking the headcount; redeploying personnel With fields no longer delivering at peak capacity, outsourcing enables redeployment of subsurface teams, and expensive technical and scientific equipment, to more valuable and strategic assets. Concerns about losing valuable resources – hired directly as the project approaches CoP, but also with an eye to the next opportunity – are also negated. Subsurface and production management can be successfully achieved with a pre-CoP team comprising a dedicated project manager, reservoir engineer and production and operations engineer. These specialists will be supported by other subsurface discipline experts on an ad hoc basis. Being productive, while preparing for CoP While the outsourcing approach represents around a 50% reduction in traditional levels of personnel, a range of activities can be performed by this small resource, including gathering data for the final well and reservoir status. Indeed, amidst a lot of industry uncertainty, one point is clear: latelife asset management should form part of the roadmap to CoP. A specialist team is both focused and in the ideal position to collate all the information required for decommissioning plans and the CoP documents required by the regulatory authorities. This also applies to preparing the CoP Application Document itself. In addition, the key tasks can be transferred, such as reserves’ booking, short and long-term forecasts, revisiting opportunities for final close-out and other forms of reporting, which are unique to each

Offshore World | 15 | June-July 2018

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FEATURES project. Field optimisation may also lead to further operating savings, enabling the pre-CoP team to be reduced, while still delivering the necessary level of specialist services. Teasing out additional value Choosing the right specialist provider enables an operator to tap into a spectrum of skills required in the process of managing mature fields, up to and including CoP, particularly field optimisation. An understanding of the full subsurface and production management requirements, together with expertise in areas such as the management of wells and facilities, can give an operator, as well as the regulator, a valuable view. This will help assure that Maximum Economic Recovery (MER) is being delivered. Each field is unique. Below are some examples of the results possible: • Streamlining the management of reservoir and subsea pipeline network by reviewing the efficiency of water injection and ‘back-out’ in the subsea pipeline network. • Using all the available data – recent seismic, well-test, inter-well connectivity and seawater composition data – to minimise deferred production. • Exploring a range of options for improving oil rate and recovery by per forming water shut-off using either thermally- or chemicallyactivated polymers at either or both injector or production wells. Considering both treatments for deployment via the subsea manifolds, rather than by direct well intervention, can reduce cost and risk. • Using a cement assurance assessment for safe, cost-effective well abandonment not just for an interval above a main reservoir, but for the entire wellbore. • Maintaining stable operations by addressing the effect caused by slugging and gas deficiency to wells and process facilities that were designed for higher production rates. • Tackling the common problem in late life of unreliable rate measurements, especially of water and oil, that are crucial to optimising production. Here, traditional modelling tools become less effective. Greater outcomes can be • achieved through closely monitoring the performance of wells and process facilities, running optimisation exercises, maintaining updated well and network models and educating all personnel to operate in a dynamic scenario, where process settings may have to be adjusted daily.

regulatory authority of viable decommissioning approaches in determining the optimal approach. Lessons learned across the world from the UKCS, Southern North Sea and Irish Sea to the Gulf of Mexico and Asia will prove invaluable in managing these maturing oil and gas regions. For many operators, outsourcing the full running of assets approaching CoP, prioritising both resources and inspection plans, and eliminating non value adding activities, will become the logical conclusion to one of the greatest priorities late-life asset management presents: adopting a cost-effective operational approach that does not compromise on safety and integrity standards. The advantages are significant with the right models, helping create a smooth transition to cessation of production. References 1. http://www.mckinsey.com/industries/oil-and-gas/our-insights/fromlate-life-operations-to-decommissioning 2. O i l & G a s J o u rn a l, J u n e 2 0 1 6 : h t t p: / / w w w. o g j. co m / a r t i c l e s / p r i n t / v o l u m e - 1 1 4 / i s s u e - 6 / g e n e ra l - i n t e re s t / w o o d m a c - u k c s decommissioning-to-ramp-up-over-next-5-years.html 3. Regulators reveal plans to spark first wave of decom in Asia, Dec 2012, DecomWorld. See: http://analysis.decomworld.com/regulation-andpolicy/regulators-reveal-plansspark-first-wave-decom-asia 4. EIC Insight Report, Upstream, May 2016 5. http://www.mckinsey.com/industries/oil-and-gas/our-insights/fromlate-life-operations-to-decommissioning 6. Based on an LR project for a major operator in the Central North Sea, taking over the full technical and operational reservoir and production management of two subsea fields.

CoP feasibility When it is time to move to CoP, weighing up the pros and cons of decommissioning options is key to application acceptance from the regulator. Technically feasible decommissioning options for fields have to be studied and subjected to formal comparative assessments (CA), using the criteria of safety, environmental, technical, societal and economic. This, often arduous, stage requires the identification of assessment scales and weighted scores, that ultimately form recommendations to the www.oswindia.com

Offshore World | 16 | June-July 2018

Steve Gilbert Director-Asset Management & Decommissioning, Energy Lloyd’s Register

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FEATURES

Oil & Gas Pro: Rise in India’s LNG Imports, Driven by Increased Consumption Ind-Ra-New Delhi-xx July 2018: India Ratings and Research (Ind-Ra) has published the July 2018 edition of its credit news digest on India’s oil and gas sector. The report highlights the trends in the sector, with a focus on domestic production, import, consumption, refining and gross under-recovery, regulatory changes and recent rating actions.

Oil & Gas Pro: Rise in India’s LNG Imports, Driven by Increased Consumption

India’s dependency on imported liquefied natural gas (LNG) has increased, indicated by stagnant domestic natural gas (NG) production and increased imports since India Ratings andbyResearch The average India’s dependency on imported liquefied natural gas2008, (LNG) opines has increased, indicated stagnant (Ind-Ra). domestic natural gas imported LNG share was 45% of the overall domestic NG consumption in FY18 as compared with 25% in FY08. (NG) production and increased imports since 2008, opines India Ratings and Research (Ind-Ra). LNG imports increased at a CAGR of 9.2% to 73 million metric standard cubic meter per day (mmscmd) in FY18 ndia Ratings and Research (Ind-Ra)due has published the Julydemand. 2018 editionThe of increased 2018. On a cumulative basis,inLNG imports were 19.1% yoy in 1QFY19. from 30mmscmd in FY08 to sustained use of NG fertilizer anduppower sectors coupled its credit news digest on India’s oil and gas sector. The report highlights the with growth of city gas distribution network has driven the domestic NG consumption. On the other hand, domestic trends in the sector, with a focus on domestic production, import, consumption, India’s crude oil production decreased 3.4% yoy in June 2018. During the month, NG production has been stagnant atand 90mmscmd with a the CAGR of volumes 0.1% ofsince FY08. has Oil led toLimited increased refining and gross under-recovery, regulatory changes recent rating actions. production Oil & Natural Gas This Corporation, India and reliance on the import of LNG, as domestic consumption has graduallysharing increasing. fieldsbeen underproduction contracts declined 4.6% yoy, 0.1% yoy and

India’s dependency on imported liquefied natural gas (LNG) has increased, 1.7% yoy, respectively. Crude oil import volume increased 6.4% yoy during June indicated stagnant natural gascontinue (NG) production and increased oil import dependency was 84.1% in June 2018 2016, and 83.9% Ind-Ra bynotes thatdomestic LNG imports to increase despite2018. theIndia’s rise crude in Asian spot LNG prices since April thus imports since 2008, opines India Ratings and Research (Ind-Ra). The average in 1QFY19. Petroleum Planning & Analysis Cell (PPAC) estimates crude imports indicating strong demand for NG and dependence on LNG imports to fulfil the same. imported LNG share was 45% of the overall domestic NG consumption in FY18 at 227 million metric tons (mmt) for FY19 (FY18: 220mmt). as compared with 25% in FY08. Figure 1

% Share of LNG Imports and Domestic NG Production % share of domestic gas production

% share of LNG imports

100% 80%

FY14

FY15

FY16

FY17

FY18

60% 40%

20%

0% FY08

FY09

FY10

FY11

FY12

FY13

Source: Ind-Ra, Ministry of Petroleum and Natural Gas, PPAC

In June and 2018, NG refining throughput waswas 21.9mmt, up 9.1% yoy. The refiningthe LNG imports increased at a CAGR of 9.2% to production 73 million metricwas standard cubic Furthermore, In June 2018, NG 2.8% yoy lower consumption 15.9% higher. During throughput was up 5.0% yoy in 1QFY19. Public sector refineries processed higher meter per day (mmscmd) in FY18 from 30mmscmd in FY08 due to sustained month, production volumes of Oil & Natural Gas Corporation Limited, Oil India Limited and private/joint venture demand. The increased use of NG in fertilizer and power sectors coupled with volumes on a yoy basis, supporting the overall increase in the throughput. During fields declined 1.1% yoy, 7.1% yoy and 7.1% yoy, respectively. The increase in consumption was on account of an growth of city gas distribution network has driven the domestic NG consumption. the month, India’s petroleum product output increased 12.0% yoy to 22.7mmt. increase domestic demand. domestic was met by a 39.0% increase LNG imports during June On a cumulative basis, yoy the production wasin6.6% yoy higher in 1QFY19. On the otherin hand, domestic NG productionThe has been stagnantdemand at 90mmscmd 2018. Onofa0.1% cumulative basis, LNG imports were upimport 19.1% yoy in 1QFY19. with a CAGR since FY08. This has led to increased reliance on the of LNG, as domestic consumption has been gradually increasing.

India’s crude oil production decreased 3.4% yoy in June 2018. During the month, the production volumes of Oil &

Natural OiltoIndia declined 4.6% yoy, 0.1% Ind-Ra notesGas that Corporation, LNG imports continue increaseLimited despite theand rise fields in Asian underproduction sharing Vivek contracts Jain, yoyLNG andprices 1.7% respectively. Crude import increased 6.4% yoy during Associate DirecJune tor, 2018. India’s crude oil spot sinceyoy, April 2016, thus indicating strongoil demand for NGvolume and India Ratings & Research Private Limited dependence on LNG imports was to fulfil84.1% the same.in June 2018 and 83.9% in 1QFY19. Petroleum import dependency Planning & Analysis Cell (PPAC) E: Vivek.jain@indiaratings.co.in estimates crude imports at 227 million metric tons (mmt) for FY19 (FY18: 220mmt).

Source: Ind-Ra, Ministry of Petroleum and Natural Gas, PPAC Furthermore, in Junerefining 2018, NG production was was 2.8% yoy lower and up NG 9.1% yoy. The refining throughput was up 5.0% yoy in In June 2018, throughput 21.9mmt, consumption was 15.9% higher. During the month, production volumes of Oil 1QFY19. Public sector refineries processed higher volumes on a yoy basis, supporting the overall increase in the Ashish Agrawal &throughput. Natural Gas Corporation Limited, Oil India Limited and private/joint venture During the month, India’s petroleum product output increased 12.0% yoy to 22.7mmt. On a cumulative Analyst fields declined 1.1% yoy, 7.1% yoy and 7.1% yoy, respectively. The increase in basis, the production was 6.6% yoy higher in 1QFY19. India Ratings and Research Private Limited consumption was on account of an increase in domestic demand. The domestic E: ashish.agrawal@indiaratings.co.in demand wasPPAC met by aand 39.0% yoy increase LNG imports during June Source: Ministry ofinPetroleum and Natural Gas www.oswindia.com

Offshore World | 18 | June-July 2018

AC OGP July2018PK1_AA1PK2_Updatedpkfinal

July 2018

FEATURES

Marine Insurance: Minimising Risks Marine insurance is the oldest form of Insurance and closely related to the development of trade in the world. It was essentially developed to cover the uncertainty associated with sea voyage. It is basically a contract between the Insured and the Insurer where in the Insurer agrees to indemnify the insured if the items covered are faced with any uncertainty subject to the warranties and exclusions in the policy.

t goes without saying that maritime transportation has shared the biggest proportion of fulfilling of this worldwide demand/supply of crude oil and petroleum products. But transportation of oil and gas by the Sea is involved with many risks and hazards, which give rise to destructive consequences such as loss of goods, loss of life, injuries and environmental damaging such as spillage of oil and gas and also pollution. This whole business falls very expensive, therefore in order to avoid any loss because of such events and happenings, in the interest of the corporation and the transporter, it is always beneficial to have a back-up like a marine insurance. Marine insurance is the oldest form of Insurance and closely related to the development of trade in the world. It was essentially developed to cover the uncertainty associated with sea voyage. It is basically a contract between the Insured and the Insurer where in the Insurer agrees to indemnify the insured if the items covered are faced with any uncertainty subject to the warranties and exclusions in the policy. Since there are various plans and policies which indicate about covering not just the cargo but also the vessel, the transporter can choose and avail of the best policy that suits his business the best. Marine Insurance or now popularly known as Transit Insurance is destination specific. Marine Policies are agreed valued policies ie the sum insured is fixed on the basis of the agreement of insured and insurer. It is a freely assignable policy ie at the time of loss whoever has the insurable interest on the items is the beneficiary of the insurance policy. The policy has to be in place before the start of transit. As far as the insurance processing goes there are three essential things that need to be present for transit insurance to be effected: • Buyer • Seller • Third Party Transporter Two types of policies • Open Marine - Annual Policy for regular, frequent and multiple transits during a period. Here the insured takes a policy for a sum insured for say ` 1 crore and covers a number of transits and to various places as mentioned in the policy. Declarations for each and every transit coming within the purview of the policy as to be submitted to the Insurance Company. The policy lapses if the sum insured is exhausted on or before the expiry of the policy period. As such open policy has a unique feature of enhancement of sum insured ie midterm increment of sum insured as per the policy rate during the tenure of the policy.

In order to issue the open policy an important point that needs to be kept in mind is the PSL ie per sending or limit per conveyance. This is the maximum amount of cargo that can be sent in a single mode of conveyance. • Specific Marine - One time policy for single risk. Destination Specific. Covers individual shipments. The sum insured and destination is fixed and it cannot be enhanced in the middle of the transit. The policy expires as soon as the material reaches the destination. The policy period is 90 days from the date of submission of premium. The premium has to be submitted before transit starts. Coverages covers loss or damage to the subject matter insured reasonably attributable to/ caused by: 1. Fire or explosion 2. Earthquake, volcanic eruption or lightening 3. Vessel being stranded, grounded, sunk or capsized 4. Overturning or derailment of the land conveyance 5. Collision or contact of vessel with external object other than water 6. Discharge of cargo at port of distress 7. General average 8. Jettison 9. General Average and Salvage charges 10. Both to Blame clause 11. Entry of sea or lake water into vessel craft hold conveyance container lift van or place of storage. 12. Washing overboard 13. Total loss of any package lost overboard or dropped whilst loading/unloading Exclusions There are certain conditions that are not covered under the policy. Some of the standard exclusions are as follows: • Loss damage or expense attributable to wilful misconduct of the Assured • Ordinary leakage, ordinary loss in weight or volume, or ordinary wear and tear of the subject-matter insured • Loss damage or expense caused by insufficiency or unsuitability of packing or preparation of the subject- matter insured • Loss damage or expense caused by inherent vice or nature of the subjectmatter insured • Loss damage or expense proximately caused by delay, even though the delay be caused by a risk insured against • Loss damage or expense arising from insolvency or financial default of the owners managers charterers or operators of the vessel • Loss damage or expense arising from the use of any weapon of war employing atomic or nuclear fission and/or fusion or

Offshore World | 19 | June-July 2018

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FEATURES • • • • • •

Shut out cargo clause – In the event of the Insured’s interest being “shut-out” from the vessel declared, this Contract extends to cover the Interest whilst waiting on the wharf, quay or pier or transfer to and whilst at another wharf, quay or pier, continues until delivered to the final destination. Container Clause - Containers that are transported at the Insured’s risk can be covered

•

Other like reaction or radioactive force or matter. Un sea-worthiness of vessel or craft, Unfitness of vessel craft conveyance container or liftvan for the safe carriage of the subject-matter insured War civil war revolution rebellion insurrection, or civil strife arising therefrom, or any hostile act by or against a belligerent power Capture seizure arrest restraint or detainment (piracy excepted), and the consequences thereof or any attempt thereat derelict mines torpedoes bombs or other derelict weapons of war Caused by strikers, locked-out workmen, or persons taking part in labour disturbances, riots or civil commotions caused by any terrorist or any person acting from a political motive

•

Potential Buyers: • Logistics Operators • Importers • Traders • Manufacturers • Exporters • Infrastructure Projects

Add-on Covers • SRCC – Strike, Riot and Civil commotion • War – only for export and import policies • Intermediate Storage – To cover intentional and voluntary storage during ADVERTISE TO EXPAND Transit. your reach through Concealed damage clause – to cover any loss or damage discovered • on opening containers, cases and/or packaging after reaching the destination. This extension is usually available for 15 or 30 days after the arrival of goods at destination. • Label clause – Where loss or damage affects labels and/or capsules and/or wrappers, the Insurer agrees to pay the cost of new labels and/ or capsules and/or wrappers any associated labor cost.

Mr Amit Agar wal, Direc tor Ideal Insurance Brokers Pvt Ltd.

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Environmental Considerations in Decommissioning of Offshore Facilities In our country, there is no clarity on applicable regulations on decommissioning of offshore facilities except Site Restoration and Abandonment Guidelines for Petroleum Operations by the DGH. This is our experience that whenever issue of decommissioning comes, companies in India are not sure from where to start, what are the applicable regulations required to meet , what documents are to be prepared to move forward and how many regulating agencies are required to be contacted? Through this review on decommissioning of offshore facilities, an effort has been made to bring clarity to the readers or the concerned petroleum companies. Further it is also made very clear that this particular article solely focuses on the Environmental Consideration of decommissioning of offshore facilities

et us first understand what the term decommissioning means .Decommissioning usually is the part of an initial agreement when a company signs a lease for the offshore Oil and Gas exploration or Production, Right-of-way or Right-of-useand- Easement, the well, that is for safely plugging the hole in the earth’s crust and disposing off the equipment which is used to support the production. This process is critical for environmental protection after a well is drilled, utilized for the production, is plugged and sealed when it is exhausted in the outer continental shelf.

is applicable upto territorial waters. Offshore facilities located beyond territorial water i.e. in international water be dealt as per agreed international conventions or provisions of April 2017 Directorate General Hydrocarbon guidelines on the subject be followed.

Whereas guidelines on Site Restoration and Abandonment for Petroleum Operations on the subject clearly states i.e.

• The 1958 Geneva Convention on the Continental Shelf (Geneva Convention). The Geneva Convention determines the sovereign rights of coastal States to explore the continental shelf and produce its natural resources. Under Article 5(5) of the Geneva Convention, any installations on the continental shelf which are abandoned or disused must be entirely removed.

(a) Decommissioning means • Ending oil or gas operations; and • Returning the lease to a condition that meets the requirements of the regulations and other agencies that have jurisdiction over decommissioning activities. (b) Obstructions means • Struc tures, equipment, or objec ts that were used in oil and gas operations or marine growth on such structures that, if left in place, would substantially hinder other existing users of the seafloor, may be considered as an obstruction. Such obstructions may be included, but are not limited to, shell mounds, wellheads, casing stubs, mud line suspensions, well protec tion devices, subsea trees, jumper assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and power cables.

Environmental Considerations at International Conventions India being signatory to a number of international conventions relevant to offshore oil and gas decommissioning by which the issue can be addressed;

• The 1982 United Nations Convention on the Law of the Sea (UNCLOS) (which modiﬁed the Geneva Convention). Article 60 of UNCLOS states that removal of installations or structures in the exclusive economic zone of a coastal State should take into account generally accepted international standards established by the competent international organization. In addition, Article 210 of UNCLOS requires States to adopt laws and regulations to prevent pollution from dumping at sea and requires national laws to be no less effective than global rules and standards in this regard.

What should be the Decommissioning approach?

• The 1972 United Nations Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (London Dumping Convention). The 1996 protocol to the London Dumping Convention broadened the definition of “dumping” to include requirements for abandonment or toppling at site of platforms or other man-made structures at sea. The International Maritime Organization (IMO) is responsible for administering the London Protocol.

Ideally decommissioning must be conducted in accordance with prior approval of concerned regulatory agencies especially an approval on Environmental Management Plan (EMP) or which must include risk-based analysis to ensure activity risk levels are reduced to the extent practicable, to acceptable levels and must ensure affected stakeholders have been adequately consulted to ensure risks are appropriately assessed and impacts are understood. However, as per the prevailing regulation in Indian law it

IMO Guidelines The International Maritime Organization (IMO) is the competent organization for the purposes of Article 60 of UNCLOS. In 1989 the IMO adopted Resolution A.672 (16) “1989 Guidelines and Standards for the Removal of Offshore Installations and Structures on the Continental Shelf and Exclusive Economic Zone” (IMO Guidelines). Although the IMO Guidelines should be taken into account under UNCLOS.

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FEATURES The general requirement of the IMO Guidelines is that all installations and structures on any continental shelf or any exclusive economic zone should be removed except where such non-removal or partial removal is consistent with the IMO Guidelines, as summarized below.

OPGGSA. These directions could permit the partial removal or leaving equipment or other property in-situ if it is not being used or to be used by a titleholder. Section 572(3) of the OPGGSA is also subject to any other provision of the OPGGSA or regulations made under the OPGGSA.

Under the IMO Guidelines, any non-removal or partial removal decision should take into account:

Importantly, section 270 of the OPGGSA addresses the requirements for the surrender of a title, which is typically the final step taken at the end of a title’s useful life. Under section 270, the Joint Authority must not unreasonably withhold consent to the surrender of a title if (among other things) a titleholder has removed all property brought onto the area to be surrendered or made arrangements regarding that property that are satisfactory to NOPSEMA.

Potential effects on safety of navigation or other uses of the sea; • rate of deterioration of materials and possible future effect on the marine environment; • effect on the marine environment; • potential for materials to move on the sea bed; • cost, technical feasibility, and safety of personnel; • and any new uses for the installation or structure remaining on the sea-bed or other reasonable justification. IMO Guidelines requires ; • ensuring that materials left on the sea-bed do not adversely affect navigation or the marine environment. • States should identify a responsible party to maintain aids to navigation and monitor the condition of materials under specific plans for these purposes. • States should also ensure that the ownership of installations and structures that have not been entirely removed is unambiguous and that responsibility for maintenance and future damages is clearly established. In 2000 the IMO adopted “Specific Guidelines for Assessment of Platforms or Other Man-Made Structures at Sea” for use by national authorities where disposal of a platform or other structure at sea is to be disposed off by dumping. Commonwealth Provisions Commonwealth legislation relating to offshore oil and gas decommissioning also applies to petroleum facilities located in waters that extend beyond 3 nautical miles from the coastline and may, in some circumstances, be relevant to water under the jurisdiction of State or Territories. The purpose of the legislation is primarily to regulate resource management, safety and environmental impact. Offshore Petroleum and Greenhouse Gas Storage Act (OPGGSA) The principal Commonwealth legislation relating to offshore oil and gas decommissioning is the Offshore Petroleum and Greenhouse Gas Storage Act 2006 (OPGGSA).

The Explanatory Memorandum to the Offshore Petroleum Bill in 2005 expressly contemplates the IMO Guidelines where “arrangements satisfactory to the Designated Authority” [now NOPSEMA] are permitted, stating these allow “an operator to leave or partially remove certain items if the complete removal involves significant cost or safety implications”. Decommissioning an offshore facility is a “petroleum activity” for the purposes of the Offshore Petroleum and Greenhouse Gas Storage (Environment) Regulations 2009 made under the OPGGSA (Regulations). Under the Regulations, NOPSEMA determines the acceptability of a decommissioning proposal through its acceptance of an environment plan prepared by the titleholder. The Environment Plan must demonstrate to NOPSEMA that the environmental impacts and risks of the activity will be reduced to “as low as reasonably practicable” (ALARP). Issues to be considered in an ALARP assessment are broad and are discussed in more detail in Section 5 of these guidelines. Environmental Protection and Biodiversity Conservation Act (EPBC Act) The EPBC Act provides for the environmental impact assessment and approval of the proposals that may involve significant impact to a matter of National Environmental Significance. Projects assessed and approved under the EPBC Act will be subject to committments made by the proponent and conditions that may have been imposed by the relevant Environment Minister. Since 2014, all petroleum activities undertaken in Commonwealth waters in accordance with the OPGGSA have been approved as “approved classes of actions” that do not require referral, assessment and approval under the EPBC Act. Decommissioning offshore facilities is an approved class of action and is therefore subject to NOPSEMA’s regulation. Regional conventions : Oslo Paris Commission (OSPAR) In addition to the international legislative framework, there are a number of

The National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) assesses Environment Plans required under the regulations for decommissioning, which may include full or partial removal of facilities.

regional conventions which govern marine disposal in specific areas. However

Section 572(3) of the OPGGSA contains a general requirement for a titleholder to remove “all structures that are, and all equipment and other property that is, neither used nor to be used in connection with the operations”.

.The North East Atlantic is governed by OSPAR (the area reaches from the east coast of Greenland to the west coast of continental Europe and stretches from the Arctic down to the southern most tip of Europe at Gibraltar).

Section 572(3) of the OPGGSA is subject to directions by NOPSEMA or the responsible Commonwealth Minister under subsections 574, 574A and 574B of the

Similar conventions govern other seas such as Barcelona Convention (BARCOM) for the Mediterranean and Helsinki Convention (HELCOM) for the Baltic Sea.

India is not signatory to this convention. But when the issue of offshore monitoring comes, the best practicing organizations in India do follow the provisions of OSPAR

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FEATURES OSPAR is an international convention drawn up in 1992 and which came into force in March 1998. It replaced the 1972 Oslo Convention (on dumping from ships) and the 1974 Paris Convention (on discharges from land) to protect the marine environment of the Northeast Atlantic from pollution. The Convention’s main roles are to control the disposal of all waste at sea and discharges from land. There are 16 contracting parties including the UK, and the EU in its own right.

This review is intended as a starting point for discussion between industry, government and community in the development of a recommended approach for decision-making on decommissioning the oil and gas facilities in territorial or International waters from following point of views;

The OSPAR Convention framework works alongside international legislation governing the removal of structures. Therefore, prior to the change to OSPAR regulations in February 1999, the OSPAR guidelines were only called upon for structures over the IMO’s required size for total removal (i.e. structures in waters deeper than 100 metres and weighing more than 4,000 tons). This accounted for some 80% of the structures in the North Sea.

The legal framework around decommissioning is evolving. It initially focused on full the removal of all offshore installations, but has more recently recognized other options, such as in-situ decommissioning, may provide better overall benefits. The key components may include:

In July 1998, at the OSPAR Ministerial meeting in Portugal (Sintra), the section of the Convention governing the disposal of offshore installations was reviewed and a new regulatory framework – Decision 98/3 – now exists which no longer permits any disposal at sea of offshore structures. OSPAR Decision 98/3 now requires the following: • All topsides of all structures must be removed to shore. • All sub-structures or jackets weighing less than 10,000 tons must be totally removed and brought to the shore for reuse, recycling or disposal . • For sub-structures weighing over 10,000 tons, an assessment will be made on a case to case basis as to whether they should be totally removed or whether the footings might be left in place. • Derogation may be considered for the heavy concrete gravity based structures listed in Annex 1 of the Decision as well as for floating concrete installations and any concrete anchor-base which results, or is likely to result, in interference with other legitimate users of the sea. • Exceptions can be considered for other structures when exceptional and unforeseen circumstances resulting from structural damage or deterioration or other reasons which would prevent the removal of a structure. National and Local Legislation Following relevant legislation and directives of the concerned organization be considered on the subject matter ; i. Merchant Shipping Act. ii. National Oil Spill Disaster Contingency Plan. iii. EIA notification. iv. CRZ notification, Wild Life Act, Eco Sensitive Area, Ministry of Environment, Forest and Climate Change. v. Concerned navigation authorities. vi. Department of Animal Husbandry, Dairying and Fisheries (DoF) within the Ministry of Agriculture and Farmers Welfare (MoA&FW) . vii. State Pollution Control Boards (SPCB) & Disaster Management Authority. viii. Directives of Oil Industry Safety Directorate , Directorate General Hydrocarbon and Ministry of Petroleum and Natural Gas. www.oswindia.com

• Prevailing position on regulatory requirements. • Environmental Considerations

• A robust and uniform policy, legal and regulatory framework that specifically addresses decommissioning. • methodology for assessing decommissioning options and comparing their relative /Environmental Impact and also impacts to identify the option that reduces the risks to as low as reasonably practicable (ALARP) and • Stakeholder consultation and engagement . Lastly, due to the significant diversity of facilities installed to access hydrocarbon resources, determining the appropriate decommissioning option for a specific installation or facility needs to be considered on a case to case basis. In addition before decommissioning Environment Impact assessment be done considering all the aspects of marine environment contamination point of view including Oil Spill, toxicity, temperature, fisheries, flora fauna etc. including applicable prior regulatory permission. Guidelines to both offshore Oil & Gas Production Site Abandonment The following sections refer to both offshore oil and gas production site abandonment. These guidelines are not prescriptive but allow flexibility within the existing regulatory framework. Government authorities and their respective roles on the Abandonment Plan The responsibilities of various authorities listed below are categorized into the following. i. Approval role: These authorities will need to approve the Abandonment Plan. ii. Consulting role: These authorities will play an advisory role, providing their inputs on the Abandonment Plan, if any, in a time bound manner. iii. Information only: These authorities will be informed of the Abandonment Plan. The Abandonment Plan will be submitted to the Oil Industry Safety Directorate (OISD) (for offshore production sites only)/ Directorate General of Mines Safety (DGMS) (for onshore production sites only) with a copy to the authorities with ‘consulting role’ for comments, if any, within 45 days of submission of Abandonment Plan in line with the guidelines. Approval Role Ministry of Petroleum & Natural Gas (MoPNG) – Approval role [through Management Committee (MC)] ► Directorate General of Hydrocarbons (DGH) – Approval role (through MC) ► Oil Industry Safety Directorate (OISD) – Approval role (for offshore production sites only) ►

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FEATURES Consulting Role ► Ministry of Environment, Forest and Climate Change (MoEF&CC) – Consulting role for Abandonment Plan (However, the Environmental Impact Assessment (EIA), where applicable, would need to be approved by the MoEF&CC) ► Ministry of Defence (MoD) – Consulting role (for offshore production sites only) ► Ministry of Shipping (MoS) – Consulting role (for offshore production sites only) ► Department of Animal Husbandry, Dairying and Fisheries (DoF) within the Ministry of Agriculture and Farmers Welfare (MoA&FW) – Consulting role (for offshore production sites only) ► State Pollution Control Boards (SPCB) – Consulting role (for onshore production sites and offshore production sites up to 12 nautical miles/ jurisdiction of EP Act ) Information Only ► State maritime board/ wild life and forest department – Consulting role for onshore production sites only ► Ministry of Water Resources - Information only (for onshore production sites only) ► State Governments (concerned departments) - Information only (for onshore production sites only) ► Coastal State Government nearest to the offshore production site – Information only (for offshore production site only) ► State, District and Local Authorities - Information only (for onshore production sites only) During project execution, necessary permits and consents would have to be taken by the Contractors from relevant authorities in line with existing rules and regulations. Regulatory Requirements It is essential that the Contractor carrying out a decommissioning project has a clear understanding of relevant regulations. Administration of a decommissioning project should not be strictly limited to regulations. In addition to the regulations, an attempt should be made to provide relevant background information and asset history. Additionally, consideration should be given to issues which impact decommissioning activities. These include, but are not limited to, certain provisions regarding impact on land, protected areas, water and endangered species and artificial reef programs. The regulations with respect to decommissioning of offshore production sites shall be administered by the Oil Industry Safety Directorate (OISD) while the Directorate General of Mines Safety (DGMS) shall administer decommissioning of onshore production sites. In addition, it is envisaged that establishment of artificial reefs for offshore platforms shall be administered by the OISD. Note 1: These Site Restoration Guidelines for Petroleum Operations are applicable only for field abandonment upon cessation of production from producing fields only. However, the Contractor shall have the flexibility to carry out well Plugging and Abandonment (P&A) and flushing/ cleaning activities on a stand-alone basis with the approvals from the Management Committee. Note 2: The Contractor shall submit the third party audit report on the contractor’s work completion dossier to OISD/DGMS and DGH which shall be considered as certification of completion of the site restoration/decommissioning/ abandonment work.

Environmental Impact Assessment (EIA) Currently, there are no specific guidelines in India for Environmental Impact Assessments for decommissioning of Oil & Gas assets. Minimum requirements should therefore be determined and it is recommended that offshore and onshore Oil & Gas producing assets. EIAs for offshore and onshore areas in India should be formulated. The EIA for the selected decommissioning methodology should take into account environment protection measures in consultation with the MoEF&CC on a case to case basis and may not be mandatory in all cases. Approved EIA report for the selected concept will be submitted by the Contractor to OISD along with site restoration plan. Handling of Naturally Occurring Radioactive Material (NORM) Identifying, labeling, maintaining, storing and disposing of equipment contaminated with Naturally Occurring Radioactive Material (NORM) shall follow the guidelines of the Department of Atomic Energy (DAE). Site Restoration Fund The Site Restoration Fund (“SRF”), where applicable, is governed by the relevant provisions of the respective Production Sharing Contracts (PSCs) and the Site Restoration Fund Scheme (SRFS) of 1999. Regarding Site Restoration Fund, following guidelines are made: • Contractor will open SRF account immediately after first commercial oil/gas production. • In the case of new fields, Contractor can alternatively submit Bank Guarantee (BG) for the initial period up to 3 years after first commercial oil/gas production. The Contractor shall create SRF account for the subsequent years of PSC period. • In the case of existing fields with commercial production, where SRF is not yet established, the Contractor can alternatively submit Bank Guarantee within 6 months after policy guidelines notification for a period up to 3 years. The Contractor shall create SRF account for the subsequent years of PSC. • The Amount of SRF or BG will be in accordance with decommissioning estimates as proposed by the Contractor and approved by Management Committee. • The funding in SRF account or BG amount will be calculated using Unit of Production method i.e. Reserve of the field to Production ratio. • Due to the varying operating lives of individual assets and changes in resource costs, decommissioning and site restoration costs may be evaluated and updated every 3 years. The decommissioning cost estimate, duly assessed by a qualified independent third party, will be submitted by the Contractor to the DGH. The revised estimates will become the basis for amount in SRF or BG. The withdrawal of funds from SRF account is governed by para 8 of the SRFS of 1999. To provide further guidance in accordance with para 8, it is recommended that the following additional steps need to be followed: • The Contractor shall propose estimates of the site restoration activities in the Annual Work Programme & Budget (WP&B) to the Management Committee including provisional work schedule and corresponding estimated payment on a Financial Year Basis. • Based on such approved Work Progress and Budget (WP&B), the Contractors would be allowed to withdraw funds in four or more phases from SRF account towards expenditure. The Contractors shall submit to the DGH, a phase-wise

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FEATURES

• •

utilization Certificate validated by independent third party who is acceptable to Management Committee, showing utilization of funds during or at the end of each phase. For release of advance for subsequent phase, Contractor to ensure that utilization Certificate is submitted for 75% of the funds drawn for the current phase and 100% of the funds drawn for all previous phases. As an alternative, the contractor shall have an option of withdrawing an advance of up to 100% of the fund required for Site restoration and abandonment as per the plan approved by the Management Committee by submitting Bank Guarantee of an equivalent amount. Within 60 days after end of a financial year, the Contractors should submit final expenditure and utilization statement for previous year. In case of BG amount, the BG amount can be adjusted/ reduced (on pro-rata basis) by the Contractor on an annual basis at the end of the financial year in accordance with the value of balance site restoration work to be completed as per the approved Abandonment Plan. The Contractor would undertake site abandonment activities as per the approved Abandonment Plan and submit the completion certificate. The contributions to the SRF account should be used only for the purpose of Field Abandonment & Site Restoration by all parties. The balance amount in SRF after Site restoration and abandonment shall be dealt with in accordance with provisions of PSC and SRF Scheme, 1999.

Commencement of Site Abandonment Regarding notice to the Government for commencement of site abandonment and approval of the Site Restoration Plan, • An estimated high level schedule for the abandonment should be submitted to the DGH for review one year prior to the expected cessation of production. Shorter time frames may be allowed by DGH if necessary. • The Site Abandonment and Restoration Plan should be submitted to the OISD/ DGMS for approval not later than 1 year after cessation of production. • Abandonment Plan shall be approved by the OISD/DGMS within 60 days of submission of the Abandonment Plan by the Contractor in line with these guidelines. In case OISD/DGMS has any query regarding any deficiencies in the documentation, the approval shall be granted by OISD/DGMS within 15 days of receipt of the satisfactory reply and correct relevant document from the Contractor. • Initiation of abandonment should begin as per timelines approved in the abandonment Plan, subject to all regulatory approvals, permits, clearances etc being granted in a timely manner. Guidelines for Decommissioning Offshore Production Sites in India (a) Decommissioning means: (1) Ending oil or gas operations; and (2) Returning the lease to a condition that meets the requirements of the regulations and other agencies that have jurisdiction over decommissioning activities. (b) Obstructions means: (1) Structures, equipment, or objects that were used in oil and gas operations or marine growth on such structures that, if left in place, would substantially hinder other existing users of the seafloor, may be considered as an obstruction. Such obstructions may include, but are not limited to, shell mounds, wellheads, casing stubs, mud line suspensions, well protection devices, subsea trees, jumper assemblies, umbilicals, manifolds, termination skids, production and pipeline risers, platforms, templates, pilings, pipelines, pipeline valves, and power cables. www.oswindia.com

Note: Various terms such as Site Restoration Plan, Abandonment Plan, Decommissioning Plan, Site Restoration and Abandonment Plan, are used interchangeably. However, they all mean the same document. Cessation of Production Within 180 days upon cessation of production, Contractor shall notify the MoP&NG/ DGH/ OISD, that all production of the facility has ceased and submit the Abandonment plan to the OISD within one year of cessation of production. General Decommissioning Requirements The guidelines on decommissioning requirements are as follows. •

Decommission wells by permanently plugging the wells. Sub-sea well head structures, Christmas trees, casings and tubings can be left in-situ provided they are stable in place and they do not have significant risk of interference with potential users of the site. The decommissioning methodology for Subsea well head structures, Christmas trees, casings and tubings shall be decided by a transparent and objective comparative assessment process which will take into account factors including geotechnical aspects, erosion processes, environmental considerations and safety etc.

•

Platforms may be removed as per IMO resolutions / guidelines. Reefing may be permitted if considered environmentally beneficial.

•

Subsea hardware and pipelines are to be decommissioned and left in-situ, provided the geotechnical, engineering analysis and other information demonstrate that hardware and pipelines are stable. The pipeline decommissioning methodology shall be decided by a transparent and objective comparative assessment process which will take into account factors including geotechnical aspects, erosion processes, environmental considerations and safety etc.

•

Where piling or conductors are severed, these should be removed to a level at or below the mud line.

•

Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of the seafloor, and does not cause undue or serious harm or damage to the human, marine, or coastal environment.

Application Process for Decommissioning of Offshore production sites • Submit preliminary schedule to mc, seek work program and budget approval for studies • Carry out appropriate studies towards development of abandonment plan • Submit proposal for abandonment plan to OISD to consult other relevant stakeholders • (mos, mod, moef & cc, dof, spcb) oisd grants approval • Seek mc approval of abandonment plan and work program and budget for abandonment • Carry out abandonment activities as per approved abandonment plan • Cessation of production • Mc concurrence • Inform other relevant stakeholders

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FEATURES Note: The Contractor shall have the ﬂexibility to carry out well P&A and ﬂushing/ cleaning activities on a stand-alone basis with the approvals of the Management Committee. Well Plug and Abandonment Wells P&A shall be carried out in accordance with OISD Standard 175. Deviations from OISD standard 175, if any, shall be submitted to the OISD for approval on a case to case basis. Rigless well abandonment is a viable option. The Contractors should have the option to abandon a well in the most economical, safe manner of their choice. Project specific procedures for Rigless P&A shall be submitted to OISD for approval. Each Reservoir isolation plug(s) must pass one or both of the following tests to verify plug integrity: • •

A pipe weight of at least 15,000 pounds on the plug; or A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes.

Decommissioning platforms and other facilities All platforms and other facilities must be decommissioned as per the approved Abandonment Plan. All production risers must be flushed with seawater before they are removed. Information to be included in Abandonment Plan for a Platform or other facility Submit the following information (as relevant) as part of the Abandonment Plan for approval to the OISD: (a) Identification of the applicant including: • Contractor; • Address; • Contact person and telephone number, email, fax and • Shore base. (b) Identification of the structure that will be decommissioned including: • Platform Name • Location (lease, area, block, and block coordinates); • Date installed (year); • Proposed date of decommissioning (Month/Year); and • Water depth. (c) Description of the structure to be decommissioned including: • Configuration (attach a photograph or a diagram); • Size; • Number of legs/casings/pilings; • Diameter and wall thickness of legs/casings/pilings; • Whether piles are grouted; • Brief description of soil composition and condition; • The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and (d) Identification of the purpose, including: • Lease expiration date; and • Reason for removing the structure.

(e) An overview of the removal method, (f) Plans for transportation and disposal (including as an artificial reef ) or salvage of the removed platform. (g) The results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site. (h) Plans to protect archaeological and sensitive biological ecosystem during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures to take to minimize such impacts. (i) A statement whether or not divers will be used to survey the area after removal to determine any effects on marine life. Information to be submitted once a platform or other facility has been decommissioned. Within 90 days after the decommissioning of a platform or other facility, submit a written report to the OISD that includes the following: (a) A summary of the decommissioning operation including the date it was completed; (b) A description of any mitigation measures taken; and (c) A statement signed by an authorized representative that certifies that the types and amount of explosives used in removing the platform or other facility were consistent with those set forth in the approved Abandonment Plan. Decommissioning Pipelines Pipelines are to be decommissioned and left in-situ To decommission a pipeline in-place: (a) Submit the following information as part of the Abandonment Plan for approval to the OISD: • • • • •

Reason for the operation; Proposed decommissioning procedures; Length (meters) of segment to be decommissioned. Plans for disposal and salvage Stretch of pipeline passing through eco-sensitive areas like national parks, wildlife sanctuaries and protected areas etc at land fall point and plan of their protection. (b) Pig the pipeline, unless pigging is not practical; (c) Flush the pipeline; (d) Fill the pipeline with seawater; (e) Cut and plug each end of the pipeline; (f) Where required, bury each end of the pipeline at least 1 meter below the seafloor or cover each end with sand/ concrete mattress; (g) Remove those pipeline valves and other fittings that could unduly interfere with other uses of the seafloor. Post Pipeline Decommissioning Within 90 days after the completion of pipeline decommissioning, submit a written report to the OISD that includes the following: (a) A summary of the decommissioning operation including the date it was completed; (b) A description of any mitigation measures taken; and (c) A statement signed by an authorized representative that certifies that the pipeline was decommissioned according to the approved Abandonment Plan.

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FEATURES Site Clearance Requirements of a Permanently Plugged Well, Removed Platform, or Other Removed facility After completion of abandonment activities, verify that the site is clear of obstructions by using one of the following methods: a) Sonar Cover 100 per cent of the appropriate grid area. Use a sonar signal with a frequency of at least 500 kHz. (b) A diver Ensure that the diver visually inspects 100 per cent of the appropriate grid area. Ensure that the diver uses a search pattern of concentric circles or parallel lines spaced no more than 3 meters apart. (c) An ROV (remotely operated vehicle). Ensure that ROV camera records videotape over 100 per cent of the appropriate grid area. Ensure that the ROV uses a pattern of concentric circles or parallel lines spaced no more than 3 meters apart. Post Site Clearance and Verification (a) For a well site, submit a Completion Letter within 90 days after completion of the verification activities, to include: • • • •

A signed certification that the well site area is cleared of all obstructions; The date the verification work was performed and the vessel used; The extent of the area surveyed; The survey method used.

(b) For a platform or other facility site, submit a Completion Letter within 90 days after the completion of the verification activities, to include: •

A letter signed by an authorized company official certifying that the platform or other facility site area is cleared of all obstructions and that a company representative witnessed the verification activities; • A letter signed by an authorized official of the third-party company that performed the verification work certifying that the platform or other facility site has been cleared of all obstructions; • The date the verification work was performed and the vessel used; • The extent of the area surveyed; • The survey method used. Note : Within 180 days of carrying out site clearance, the Contractor shall submit the third party audit report on the contractor’s work completion dossier to OISD/ DGH which shall be considered as certification of completion of work.

The distinction between the removal and disposal of disused offshore oil and gas installations is important as they come under very different types of legislative frameworks. Whilst interlinked, the legal requirements for removal are primarily concerned with safety of navigation and other users of the sea. The disposal of structures comes under the pollution prevention regulatory framework. The 1989 IMO Guidelines require the complete removal of all structures in waters less than 100 metres (since January 1998 – previously it was 75 metres) and substructures weighing less than 4,000 tonnes. Those in deeper waters can be partially removed leaving 55 metres of clear water column for safety of navigation13. All new structures installed after 1 January 1998 must be designed so as to be feasible for complete removal. 12 http://www.ukooa.co.uk/issues/decommissioning/framework.htm. The DTI Guidelines themselves are available on http://www.og.dti.gov.uk/regulation/ guidance/guidenote.doc. 13 This requirement is partially linked to defence requirements. Submarines require a depth of 55m to be able to remain submerged. The requirement does not apply to structures that are not removed and are left protruding above the water line. National and Local Legislation The legislation governing the decommissioning of offshore structures on the UK continental shelf involves a number of different government departments and bodies. All Government departments concerned with decommissioning and with the issuing of any permits or consents co-operate to ensure that their procedures are compatible. The international laws described above are enshrined in the UK’s national legislative framework. The principal legislation for decommissioning comes under the Petroleum Act 1998 which is administered by the DTI and which provides a framework for the decommissioning of disused offshore installations and pipelines on the UKCS. The DTI also provides operators with guidelines on how to undertake the process of decommissioning. These are described in the DTI’s Oil & Gas Directorates draft ‘Guidance Notes for Industry – Decommissioning of Offshore Installations and Pipelines under the Petroleum Act 1998’.

Monitoring and Survey Requirements of Abandoned Pipelines (a) Perform an environmental and stability baseline survey. (b) A pipeline location survey should also be carried out by the Contractor to establish stability of the abandoned pipelines, after at least one monsoon season has elapsed since the abandonment of such pipelines. (c) Post abandonment monitoring is not necessary. ANNEX 1: THE REGULATORY FRAMEWORK Note: The following information about the current regulatory framework in respect of decommissioning has been largely taken from the UKOOA website12. The process of decommissioning is regulated by international, regional and national legislation. www.oswindia.com

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J S Sharma, Ph.D., STA Fellow (Environment), Japan F o r m e r G ro u p G e n e r a l M a n a g e r (C h e m . ) - H e a d Environment, Oil and Natural Gas Corporation Limited, E-Mail: sharmajswarup@hotmail.com

Without drastic changes in current consumption patterns, coal demand is likely to remain relatively stable in the years ahead, according to BCG’s Global Energy Scenario Model. The main reason: the unquenchable thirst for energy in numerous Asian developing countries, such as India and Indonesia.

f you listen to the rhetoric, the outlook for the coal market can be summed up in one word: bleak. In Europe, political and social opposition to coal is mounting as efforts intensify to limit CO2 emissions. In the US, cheap and accessible shale gas is rapidly displacing coal. And in China, concerns about poor air quality and related health issues have caused demand for coal to fall three years in a row, from 2014 to 2016. So is coal demand about to decline globally? Is coal headed for the ash heap of history? Such a development is unlikely. Without drastic changes in current consumption patterns, coal demand is likely to remain relatively stable in the years ahead, according to BCG’s Global Energy Scenario Model. The main reason: the unquenchable thirst for energy in numerous Asian developing countries, such as India and Indonesia. The Future Of Energy Certainly, several developments could trigger a slowdown in coal demand growth, or even a contraction. These include slower than projected global GDP growth and an exceptionally fast uptake in renewable power, even faster than the rapid pace currently projected, combined with disruptive advances in renewable energy storage. Comprehensive, coordinated global regulatory action to limit greenhouse gas emissions, difficult and complex, but not impossible, could also reverse the coal trajectory. Absent such events, coal is expected to continue to play a major role in the energy market for the foreseeable future. Even amid stable global demand, however, risks will mount for those with a stake in coal. Heavy users in energy-intensive industries will need to regularly evaluate whether to shift to other power sources, given that new regulation can abruptly make coal less cost competitive. In addition, while a concerted global shift from coal is unlikely, coal-mining companies and coal-fired power plant owners face the potential of swift and unexpected regulatory changes in many markets, which could result in stranded assets. At the same time, the challenges facing coal will lead many investors to exit the sector, although those with a higher risk tolerance may look for distressed asset opportunities. Perhaps even more significant, the continued demand for coal has global implications. Most notably, it substantially reduces the likelihood that efforts to limit the global temperature increase to less than 2°C will succeed.

The Main Reason Coal Demand Will Remain Relatively Stable: The unquenchable Thirst For Energy In Developing Countries In Asia

Continued Demand—but Growing Uncertainty Coal has enjoyed nearly 200 years of continuous volume growth, with 1.6% annual growth in the past 100 years alone despite the displacement of coal by oil in transportation. Today, coal accounts for roughly one-third of global energy production. The primary reason: it is affordable, accessible, and easily stored and transported, making it well suited to meeting the energy needs of industrializing economies. It’s no surprise, then, that about 76% of global coal demand comes from China and other developing countries, which continue to add coal-fired power capacity. In 2016 alone, 70 gigawatts of new coal capacity was added globally, a net increase of 57 gigawatts, after accounting for plants taken out of use. That’s nearly 40% of the total coal-fired power plant capacity in Europe today, or the equivalent of roughly 800 megawatts of new capacity every four days. New Headwinds Emerge. Such statistics, of course, do not tell the full story. Multiple coal-fired power projects, with a total capacity of 440 gigawatts, have been cancelled, deferred, or delayed around the world over the past three years, including at least 250 gigawatts in China. Such actions stem from two developments. First, the environmental costs of coal are becoming more apparent. Coal is roughly 40% more carbon intensive per energy unit than gasoline and about 80% more carbon intensive than natural gas. It is the leading source of global carbon emissions and the second most dominant source of air pollution, after oil. Second, costs are declining for renewable energy, including centralized wind and solar power and decentralized solar prompting China, India, and other Asian countries to invest in renewable power generation. Even taking cancellations into account, however, some 220 gigawatts of new coal-fired power generation is under construction, primarily in Asia. Within Asia, demand growth is shifting from China, where coal consumption will plateau in the 2020s, to other countries. In India, roughly 50 gigawatts of new coal, fired power generation capacity is under construction, which represents about 20% of the country’s current coal-fired capacity. Meanwhile, Indonesia, Taiwan, Vietnam, Malaysia, and the Philippines are constructing coal-fired plants. Potential Disruptions in the Coal Market. There are a number of wild cards when it comes to the outlook for coal demand. Expanded access to electricity, a rapid shift to electricity for heating, or a breakthrough in electric vehicle technology, particularly in developing markets, could stoke stronger than expected power demand and, therefore, coal consumption. Advances in cutting-edge clean coal technology that enables the capture and storage of CO 2 from coal power plants, an approach that is currently cost prohibitive, could also boost coal consumption. A couple of developments could dampen growth in the demand for coal. One is the faster than expected substitution of gas for coal in the power industry. However, even under

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FEATURES

Why Coal W ill Keep Burning?

FEATURES We have modeled such a scenario, one that assumes society is able to harness roughly 40% of the potential decentralized solar capacity that is technically feasible. (The calculation of potential capacity depends on factors including the amount of solar energy reaching the earth as well as the size and structure of the global building stock and solar panel efficiency.) Even in such a scenario, however, coal demand would decline by just 1% from 2018 through 2040. Weak GDP Growth. GDP growth remains a strong driver of power demand, particularly in emerging countries. Our model indicates that a relatively low global GDP growth rate of about 3% per year between 2018 and 2040 would dampen overall energy demand; coal demand would fall by about 8% during that period.

a scenario in which shale gas reserves in China and Argentina are tapped, coal demand would still increase by roughly 0.3% annually between now and 2040. Another possible development is rapid gains in energy efficiency in buildings and appliances, which would limit coal demand growth to 0.2% annually through 2040, according to our model. Under all these scenarios, coal demand either continues to grow modestly or remains stable. What would trigger a contraction? Our model indicates three developments that, either alone or in combination could reduce the demand for coal. (See Exhibit 1.) Rapid Deployment of Renewables and Breakthroughs in Energy Storage. There is no doubt that steadily declining costs will fuel the massive deployment of renewable power in the years ahead. The question is whether the uptake could exceed even current, aggressive projections. Another uncertainty is the outlook for storage technology. Solar and wind power are now competitive with coal when the sun is shining or the wind is blowing. However, the technology for storing that power is not cheap enough to make renewables competitive with coal 24 hours a day, 7 days a week. Breakthroughs such as the development of large scale, inexpensive batteries or affordable power-to-gas or power-to-hydrogen technologies, combined with quicker than expected uptake of renewable energy globally, could change that calculation. www.oswindia.com

Comprehensive Global Regulation. A coordinated, global regulatory push to limit CO2 emissions could derail coal. Certainly, such an undertaking would be challenging and complex but it is not impossible. To succeed, an international CO2 emission reduction scheme would need to recognize the right of developing countries to continue advancing economically. And it would likely call on developed countries to provide some economic support to help developing countries shift to less carbon-intensive energy sources. To evaluate the impact of such an effort in our model, we assume that OECD countries and China stop building new coal power plants as of today (2018) and retire all plants older than 40 years by 2020 and all plants older than 35 by 2030. We also assume that the rest of the world stops building new plants by 2025 and retires all plants older than 40 by 2030. In this scenario, coal demand would decline 14% from 2018 to 2040. None of these developments would lead to an outright collapse in coal demand a fact that underscores just how entrenched coal remains in the global economy. The Outlook For Coal By Region As part of our analysis of the feasibility and impact of shifting away from coal, we

WITHIN ASIA, DEMAND GROWTH IS SHIFTING FROM CHINA, WHERE COAL CONSUMPTION WILL PLATEAU IN THE 2020Sâ&#x20AC;&#x2122; TO OTHER COUNTRIES.

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FEATURES

have divided the world into three parts: OECD countries, China, and other non-OECD nations, which we refer to as “developing countries.” As coal consumption declines in most developed countries, including those in Europe and the US, the future of coal is increasingly dependent on developing countries. Without some sort of international emissions reduction plan, the total tab for those countries to move aggressively off coal in the near term would be prohibitively high. Such calculations, however, do not factor in the long-term economic costs created by unchecked global warming. Ultimately, those costs, while difficult to project with precision, are likely to be massive and outweigh the bill for eliminating the use of coal-fired power globally. OECD Countries Move Beyond Coal. Most European power generation players have ruled out the construction of new coal plants. And utilization at existing coal-fired plants in Europe is decreasing as renewable energy sources expand. Government leaders in Germany, France, Italy, the UK, Austria, the Netherlands, Portugal, and Finland are all considering the elimination of coal-fired power generation between 2025 and 2030. A number of regulatory actions, including a

Most European power generation players have ruled out the construction of new coal plants.

hike in the price of CO2 to about $15 per ton, would effectively drive coal out of the market. In fact, under planned changes to the EU emissions trading system, CO2 prices could hit that level or higher in the 2020s. Such a move would come with significant, but not prohibitive, costs. We estimate that the stranded costs the write-offs associated with closing Europe’s coal plants would be about $100 billion. Add in the higher energy costs that would come from substituting coal-fired power with a mix of renewables and gas, and the total bill on a net-present-value basis would hit about $180 billion roughly 0.07% of the region’s cumulative GDP from 2018 through 2030. Meanwhile, the shale revolution in the US has upended the coal market, leading to annual declines of about 4.7% in coal consumption for power generation over the past ten years. This trend is likely to continue although the degree of substitution varies by region. States such as Pennsylvania and Ohio, which have established gas infrastructure, for example, have seen rapid substitution, while coal has lost little share in states such as Utah and Wyoming, which have limited existing gas infrastructure and proximity to substitutes. For the US to completely eliminate coal, the total net-present-value cost would be about $100 billion, or a relatively modest 0.04% of cumulative US GDP through 2030. The remaining OECD countries, such as Japan and Australia, typically have a younger base of coal-fired power generation and a greater reliance on coal than Europe and the US. This is particularly true in Japan, where coal-based power generation got a boost after the Fukushima accident. We estimate the net-present-value cost for these countries to eliminate coal-fired power generation to be about $150 billion, or roughly 0.08% of cumulative GDP through 2030.

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FEATURES In fact, the decline in China’s coal-fired power generation capacity, which today stands at about 920 gigawatts, is unlikely to be dramatic. Slowing Demand Growth in China. China has been the primary driver of coal demand since the early 2000s, thanks to its ever-growing need for power. In 2016, 35 of the 70 gigawatts in new capacity was in China. However, demand for coal in China has just about peaked and is likely to begin declining in the early 2020s. The government is promoting a shift from coal to less polluting sources, including renewables, in a bid to address the country’s air quality challenges. This has included a push in urban centers to move away from coal-fired heat and a drive to shutter some of the country’s older, high-polluting coal plants. At the same time, the government has curtailed coal production since 2015 as part of an effort to prop up domestic coal prices. But these efforts merely mark a reset in China’s reliance on coal not a full-scale reduction. In fact, the decline in China’s coal-fired power generation capacity, which today stands at about 920 gigawatts, is unlikely to be dramatic. For one thing, China added a significant amount of coal-fired capacity from 2000 to 2016. (See Exhibit 2.) As a result, the average age of a coal-fired power plant in China is just 11 years—and another 90 gigawatts is under construction. Given that the average coal-fired plant currently operates for about 60 years, those assets may be in use for decades to come. In addition, coal mining and production account for a significant number of jobs in China making the shutdown of such operations politically unpalatable. Finally, absent significant government intervention, gas will not be a viable substitute for coal in China. We estimate that Chinese domestic gas prices would need to hit $4.2 to $5.3 per million British thermal units (mmbtu) for natural gas to displace coal. Such prices would be possible only if China could tap into natural gas reserves at cost levels nearly as low as those in the US a possibility that is not realistic in the near term. In this environment, the steep cost of eliminating coal in China makes such a move difficult. The best option is to replace coal with a mix of renewables and gas. But such a mix is still more expensive than coal. As a result, we estimate the full net-present-value cost of substituting coal-fired power with renewables and gas in China to be $1.3 trillion or 0.55% of China’s cumulative GDP through 2030 including about $750 billion in stranded assets.

liquefaction, transport, and the construction of infrastructure to move gas inland, make it noncompetitive with coal in most cases. In fact, assuming there is no global scheme for putting a price on CO2 emissions, US gas prices would need to fall below $2 per mmbtu for LNG to be a viable option in most of these countries. That price level is about 25% below the average US Henry Hub spot price over the past five years. In addition, while renewable energy sources are growing quickly in these markets, the increasing demand for power swamps that additional capacity. India, for example, has taken decisive steps to support renewable energy development, including eliminating both import duties on critical solar parts and interstate transmission charges on the export of solar power. The government’s goal: to reach 175 gigawatts of renewable energy capacity by 2022, up from 60 gigawatts currently. But that will represent just one-third of the country’s total power generation capacity and coal is still projected to account for more than 50% of that capacity. In this environment, the costs of shifting rapidly away from coal are steep. BCG estimates that substituting coal-fired power generation with higher-cost renewables in developing countries, including balancing intermittent renewable power generation with gas, would have a net-present-value cost of more than $700 billion. This amounts to nearly 0.25% of the cumulative GDP for these countries through 2030 although some countries bear a higher share of these costs than others. This estimate includes roughly $350 billion in stranded assets, many of which would be relatively young coal-fired power plants, but does not include the sizable economic hit to these countries from closing coal mines. Even if such high costs could be addressed with a global emissions reduction plan, countries would confront major execution challenges in shifting away from coal. These would include rapidly building new low-carbon power generation and storage capacity and upgrading the power grid. Adjusting To The New Realities For decades, utilities and other energy-related businesses have been accustomed to predictable, steady demand growth, a stable technology landscape, and a relatively slow pace of regulatory change. But this stable environment is morphing into something more dynamic and less predictable. (See “Preparing for an Uncertain Energy Future.”) Preparing For an Uncertain Energy Future This new reality is particularly challenging for companies linked to the coal sector. It has major implications for companies that consume large amounts of energy, mining companies, coal-fired power generators, and investors.

Growing Coal Demand in Developing Countries. Amid energy-intensive economic growth, coal remains a primary power source in most developing markets. Even after multiple project cancellations in countries such as India, roughly 100 gigawatts in coal-fired generation capacity is under construction. The bulk of the capacity is being constructed in India, Indonesia, Taiwan, Vietnam, Malaysia, the Philippines, Pakistan, Bangladesh, and South Africa. And even more is on the drawing board.

Industrial Coal Users. The risk posed by new, strict coal regulations is very real for companies that rely on coal-fired power. Tougher regulations will increase the cost of coal use. Meanwhile, the potential upside from declining coal demand lower coal prices is limited given the fuel’s flat cost curve. That’s one reason industrial coal users need to regularly evaluate the option to switch to gas or renewables. Mining Companies. Mining operators have long-cycle investments, often putting sizable amounts of capital to work over many years to gain access to resources

The growing appetite for coal is unlikely to diminish any time soon. For one thing, natural gas cannot displace coal in these markets. That’s because these countries lack their own major cheap and accessible gas reserves and therefore would need to import liquefied natural gas (LNG). But the costs associated with LNG, including

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FEATURES While mining companies can ship their product to regions where coal is still in demand, coalfired plant operators do not have that luxury. and develop production and export infrastructure. Faced with a less certain demand outlook, coal-mining companies will need to find ways to reduce the risk of stranded assets. This will require a review of their investment plans with a more conservative approach to new developments. This approach should include a focus on projects that will yield lower-cost and higher-quality (lower ash content) resources, are located close to or within existing operational sites, or have existing export agreements. At the same time, these operators should take a hard look at options for diversifying away from coal.

At the end of the day, investors need to be ready to make decisions swiftly. Market conditions and regulations are likely to change rapidly. It will be critical to assess those changes quickly and be agile in responding. The evidence is clear that coal is likely to remain a significant component of the global power sector for the foreseeable future. Certainly, weak global economic growth or new renewable breakthroughs could limit coal demand growth. And a global regulatory backlash is always possible. However, global action to curtail or eliminate coal use would need to include a mechanism for compensating emerging economies, which simply cannot afford such action on their own. Such a development, while feasible, is not likely in the near term. Still, even if coal demand holds steady, risks particularly those related to stranded assets are rising for participants in the market. While coalâ&#x20AC;&#x2122;s 200-year run is far from over, the rules are changing.

Vertically Integrated Utilities with Coal-Fired Power Plants. While mining companies can ship their product to regions where coal is still in demand, coal-fired plant operators do not have that luxury. In addition, profitability for coal-fired plants will continue to decline as increasingly competitive renewables drive overall market power prices lower and mounting regulatory constraints push coal-fired generation costs higher. As a result, vertically integrated utilities with coal-fired plants have a decision to make. They must either improve the efficiency of their operations or sell their coal assets while a market remains for them. For those that retain coal assets, the risk of stranded assets is high. As a result, they should explore putting those coal assets into a separate entity. Walling off the coal business in a separate unit will make it easier to pursue a strategy that is appropriate for those assets. That strategy has three primary components. First and foremost, companies must relentlessly reduce costs and improve flexibility the ability to rapidly ramp energy production up and down. Second, coal-fired plant owners must find ways to limit their downside, such as by charging customers for energy capacity rather than actual consumption. Third, operators must make careful decisions about maintenance and investments, including limiting investments in new assets to those with a short payback period. In addition, investment decisions should always take into account a market price for CO2, even in regions where carbon is not yet taxed. Investors. Focused investors, including infrastructure funds and private equity firms, can find significant opportunities in distressed coal assets. To make this investment play work, however, they need to carefully manage the risks and focus on cost efficiency, flexibility, and maintenance and investment optimization, as described above.

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Despite the fact that a global exit from coal is unlikely, the risk of a major negative regulatory event in any one market is real. As a result, investors should build a diversified portfolio of assets. In fact, the declining profitability of coal plants is already driving consolidation. Larger and more focused players in coal-fired and other conventional power plants can realize significant economies of scale, including through better pricing in procurement and the ability to spread overhead costs over a larger base. And as they acquire more assets, these consolidators can invest in plants with the best potential and shut down those with weaker prospects. Offshore World | 33 | June-July 2018

Christophe Brognaux Senior Partner & Managing Director The Boston Consulting Group Brussels

ERIC BOUDIER Senior Partner & Managing Director The Boston Consulting Group Oslo

TYCHO MĂ&#x2013;NCKS Principal The Boston Consulting Group Dusseldorf

MATE GERECS Principal The Boston Consulting Group Budapest

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A PLACE FOR POSITIVE DISPLACEMENT

PD flow meters quietly excel in low-flow rate, high viscosity, and liquid and gas metering applications

ositive Displacement (PD) flow meters are the workhorses of todayâ&#x20AC;&#x2122;s flow meter world. They perform many important flow measurements most people take for granted, eg, they are widely used for metering both water and gas in residential, commercial and industrial applications. Chances are good the flow meter that measures how much water you use at your house is a PD meter. PD flow meters separate the fluid to be measured into distinct compartments of known volume. As the liquid or gas passes through the flow meter, the compartments are repeatedly filled and emptied. Flow rate is calculated from the number of times these compartments are filled and emptied. PD meters differ according to the shape and size of the compartments involved and according to whether they are designed for liquid or gas.

This measurement occurs both upstream and downstream of refineries. Oil trucks that deliver oil to peopleâ&#x20AC;&#x2122;s houses use a flowmeter to measure the amount of oil dispensed. Often this is a PD meter. Some PD meters rely on the lubricating property of oil or hydrocarbon liquid when the liquid is in contact with the measuring chamber. These meters can measure gasoline, diesel fuel, heavy fuel oil and many other hydrocarbon-based liquids. Unlike turbine meters, PD flow meters can easily handle high-viscosity liquids. For this reason, they are often used to measure petroleum at terminals, in production, and downstream for delivery. PD meters can measure heavy crude oil accurately and they are not affected by variations in velocity or viscosity of the measured product.

Positive displacement flowmeters excel where many other flow meters have difficulties: low flow rates and high-viscosity liquids. In addition, they provide a very cost-effective solution for utility applications requiring low-cost meters that last for many years; they still occupy a niche where they are the best solution. And with annual worldwide sales that exceed $500 million, PD meters will be around for many years to come.

* Process liquid applications include industrial chemicals, pharmaceutical chemicals, paints and varnishes, printing ink, dairy products, cosmetics, and many other liquid products. In many cases, PD meters provide a highly accurate measurement for a lower price than meters such as magnetic or Coriolis.

Applications for PD Meters The use of PD meters can best be understood by dividing them into water utility, gas utility, oil and industrial liquid applications: * Water utility applications mainly are for billing purposes. Water utility companies buy these meters and put them in industrial plants, commercial buildings and homes to measure how much water is used at those facilities. Just as private homes need flowmeters to measure the amount of water used, so do hotels, apartment complexes and other commercial buildings. These buildings are likely to use PD, although they may use turbine meters instead for higher volume flows. Many smaller commercial buildings use PD flowmeters to measure water use within the building. Most PD meters for line sizes of 1-1/2 or 2-in are for commercial applications. * Gas applications include billing meters to measure the amount of gas used at houses, commercial buildings, and industrial plants. The meters used for billing purposes in industrial plants such as chemical, food processing and pharmaceutical plants are different from the meters used to measure gas as part of the manufacturing process. Many of the PD meters used for gas utility measurements are diaphragm meters. However, these are being replaced by rotary meters for some applications, since rotary meters are smaller and lighter. Rotary meters are also used for non-utility gas flow measurements in industrial environments. * Oil, refined fuels and hydrocarbon products are a very large PD flow meter market segment. Some PD meters are used for loading and unloading trucks, tankers, airplanes and ships. Most of this measurement is for the purpose of custody transfer.

Change is Evolutionary Change in the PD flow meter market is more evolutionary than revolutionary. Some PD meter companies are not even currently investing in new product research. However, there are some new developments in PD meters. Some of these developments focus on improved methods to increase component manufacturing precision, eg, improved coordinate measuring machines make it possible to create more perfectly round pistons and other components, and one difference between positive displacement flow meters and new-technology meters (Coriolis, magnetic, ultrasonic, vortex and multi-variable differential pressure) is in the displays. PD meters typically compute flow by counting pulses. The pulsed output of PD meters is typically not a flow rate but a pulse value. To compute flow rate, these need to be related to time. This computation is often done not in the flow meter but in a separate totalizing device that may be panel-mounted. One potential growth path for positive displacement meters is integrating this computational capability in the flow meter instead of having it done in a separate totalizing device, and some vendors are already doing this. One aspect of transmitter technology that has not yet had a major impact on positive displacement meters is communication protocols. While some magnetic flow meter and pressure transmitter suppliers have made HART a default capability for their products, only Brooks Instrument and Bopp & Reuther have so far introduced HART versions of PD meters. It is likely that more smart PD meters will be produced in the future as new technology meets old. PD Prospects Positive displacement flow meters are a traditional technology flow meter that will be around for many years to come. Even though they face stiff competition from new technology meters in some segments, they still remain the best solution for certain applications. This market is so large that, like differential pressure flow meters, they will still be around for years from now. Positive displacement meters are very effective at making low-cost mechanical measurements for utility purposes. These include residential, commercial and industrial utility applications.

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Engineers who are in a tight spot over where to locate liquid and gas flow meters aboard offshore platforms, FPSO vessels and sub-sea Installations, will find the self-conditioning V-Cone Offshore Flow Meter from, requires a pipe straight-run that is up to 70-per cent less than other meters, resulting in significant real estate and installation cost savings that can actually exceed the cost of the instrument itself.

he advanced V-Cone operates over a wide flow range of 10:1 with low head loss and supports line sizes from 0.5 to greater than 120 inches. Accuracy is +0.5%, with repeatability of +0.1%. Petroleum production engineers can rely on the V-Cone Flow Meter for long life and low cost of ownership because it requires virtually no recalibration or maintenance over an exceptionally long life. Easy to locate and easy to install, the versatile V-Cone is ideal for new equipment designs, expansion projects or retrofits requiring new meters.

In comparison to traditional DP instruments such as orifice plates and venturi tubes, the V-Cone Flow Meter’s design is inherently more accurate because the flow conditioning function is built into the basic instrument. The V-Cone conditions fluid flow to provide a stable flow profile that increases accuracy. It features a centrally-located cone inside a tube. The cone interacts with the fluid flow and reshapes the velocity profile to create a lower pressure region immediately downstream.

The space-saving V-Cone reduces flow meter straight pipe run requirements by up to 70 per cent or more and needs only 0-3 straight pipe diameters upstream and 0-1 downstream to operate effectively. It fits in tight installations on offshore platforms, FSPO vessels as well as in sub-sea installations, while also reducing pipe material costs and installation labour costs automatically. Its space-saving design has been especially useful in accommodating compressors in such applications.

The pressure difference, which is exhibited between the static line pressure and the low pressure created downstream of the cone, can be measured via two pressure sensing taps. One tap is placed slightly upstream of the Cone and the other is located in the downstream face of the cone itself. The pressure difference can then be incorporated into a derivation of the Bernoulli equation to determine the volumetric fluid flow rate. With additional instrumentation, the mass flow rate also may be obtained.

The V-Cone’s unique no-moving parts design provides built-in flow conditioning, which nearly eliminates the upstream/downstream straight pipe runs required by nearly all flow meter technologies. Typical flow meter installations may require 10 to more than 40 straight pipe diameters upstream from the meter and 5 or more straight pipe diameters downstream to eliminate the effects of swirl and other pipeline disturbances caused by valves or elbows or elbows that negatively affect measurement accuracy. V-Cone Flow Meter is compatible with the demanding standards set by the oil/ gas production, delivery and refining industry. The testing of the V-Cone Flow Meter now conforms to the American Petroleum Institute’s API 22.2 Testing Protocol for differential pressure flow measurement devices.

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FLOW METER FOR COAL-BED METHANE & WET GAS METERING IN OFFSHORE APPLICATIONS

NEWS

Aker BP acquires 11 Total licences in Norway Aker BP has agreed to acquire Total’s interests in 11 licences on the Norwegian Continental Shelf for US$205 million. The portfolio includes four discoveries with net recoverable resources of 83 million barrels oil equivalents (mmboe), based on estimates from the Norwegian Petroleum Directorate. Two of the discoveries, Trell and Trine, are located near the Aker BP-operated Alvheim field and are expected to be produced through the Alvheim FPSO. The Alve Nord discovery is located north of the Aker BP-operated Skarv field, and can be produced through the Skarv FPSO. The Rind discovery is part of the NOAKA area where the total recoverable resources are estimated to more than 500 mmboe, and where Aker BP is working towards a new area development. Karl Johnny Hersvik, CEO of Aker BP commented: “We see a huge value creation potential in maximizing production through our operated production hubs. With this transaction, we get access to new tie-back opportunities in the Alvheim and Skarv areas, we strengthen our resource base in the NOAKA area, and we increase our interest in exploration acreage near the Ula field. These new resources will further strengthen our long-term production profile and contribute positively to future earnings.”The deal is subject to approval by Norwegian authorities.

Global Marine Group appoints three directors Global Marine Systems, trading as the Global Marine Group, appointed Ian Bryan, managing director of group operations; Mike Daniel, Managing Director of global offshore and Mark Preece, Managing Director of CWind to its board of directors effective from July 2 2018. The company, which provides offshore engineering services to the telecommunications, renewables and oil & gas industries, said these appointments expand the board from four members which include Dick Fagerstal chairman, Ian Douglas chief executive officer, Richard Fraser-Smith chief financial officer and Bruce Neilson-Watts managing director, Global Marine to seven directors, that share a combined wealth of industry and business transformation experience ensuring successful onward stewardship. Bryan, has been working for the group since August 2016, and brings a comprehensive background in marine engineering and renewable energy. He is a chartered engineer, and has successfully delivered major capital projects and launched new service lines in multiple sectors. Daniel, has led global offshore since the acquisition in 2017 and is an industry veteran with over 35 years’ experience. He directs a proven team that has an exemplary track record in successful operational delivery for major global companies such as E.ON, Shell and BP. Preece, who has worked extensively in the offshore and maritime sectors, joined CWind in 2017. He has built a solid reputation for delivering complex, high value projects, having formerly served as executive vice chairman at PDi Ltd, CEO of CEONA Offshore and CEO of Reef Subsea. Ian Douglas, chief executive officer of Global Marine Group said “Following the group’s recent successes, in particular the acquisition and subsequent integration of the Global www.oswindia.com

Offshore team and the formation of CWind Taiwan, it is now the right time to add strength to our board to further enable our future growth.” Douglas added, “We have a robust business model which brings innovative offshore engineering capabilities to multiple sectors. I’m delighted that we’ve added these three accomplished business leaders to the board, I am confident that they will add great value and that the business will benefit from their insights, commercial acumen and governance.”

DEEPA™ Boosts Oil Production from Mature Vertical Wells by up to 250% – Cleansorb, a leading provider of chemical well treatments that enhance hydrocarbon production for the international oil and gas industry, today announced that it dramatically increased oil production by up to 250% from mature vertical wells in Canada by treating them with a DEEPA™ formulation that increases the matrix permeability of the rock and simultaneously remediates nearby wellbore damage. Initially, Cleansorb developed DEEPA™ in-situ acidizing for deep matrix acidizing treatments and to stimulate production from natural fractures in carbonate formations. This was followed by ORCA™ for WBM, to remove drilling damage from water-based drill-in fluids in openhole wells, particularly in long horizontal wells, and ORCA for OBM to remove drilling damage from oil-based drill-in fluids in open hole wells. Founded in 1994, Cleansorb supports customers around the world from its global headquarters in Guildford, England. These mature vertical wells, which have been producing for nearly 40 years, are located in the carbonate Swan Hills Formation in Canada, and had a slight tendency to accumulate scale near the wellbore. “To address this issue and enhance production, the customer wanted to investigate novel approaches to treat their assets, so opted to treat them with DEEPA, which we developed to dissolve scale and enhance matrix permeability of the rock,” said Ian McKay, Director & Co-founder of Cleansorb. Production soars DEEPA, which delivers organic acid deep into the rock matrix via in-situ acid generation, increases permeability uniformly around the wellbore. To treat the Swan Hills Formation wells Cleansorb, and its local partner, formulated a custom DEEPA treatment suitable for a bottom hole static temperature of 90–110°C (194–230°F), which was then administered. Following a brief 24-hour shut-in period to allow the treatment to dissolve the scale and penetrate the rock, production in each well rose by 200–250%, and remained at that level. This result exceeded the customer’s expectations. “The proof lies in that extraordinary production improvement of 250%,” said the Vice President of Operations & Technology for the operating company. “DEEPA doesn’t let us down.” Since the initial wells were treated in the carbonate Swan Hills Formation, similar results were achieved when applied to mature wells located in sandstone formations containing 5–10% carbonate. Over time, approximately 30 mature wells in Canada have been successfully treated with DEEPA. “Because every well is different, every well will respond differently. That said, doubling production following treatment with DEEPA is not out of the ordinary,” said Ian McKay. “In this case, there was a very slight scaling tendency, so the wells had accumulated scale throughout their 40-year producing life, which was then cleared with DEEPA. Similar production improvement is certainly achievable on other mature fields with long-term scaling issues, once treated with DEEPA. It’s a very simple, straightforward way to revitalize production, effectively extending the life of a field that might have otherwise been slated for decommissioning.”

Offshore World | 36 | June-July 2018

Japan’s Inpex has announced that its operated Ichthys LNG Project has commenced production of gas from its first offshore well and that shipments are expected to start this year. The project consists of the development of the Ichthys gas and condensate field offshore northwestern Australia (in 260 meters of water depth) and a 889-kilometer gas pipeline together with an onshore LNG plant near Darwin in the Northern Territory. The produced gas will be gathered within the Central Processing Facility (Ichthys Explorer) where it will be separated into gases and liquids. Thereafter, the liquids will be piped to the nearby Floating Production, Storage and Offloading (FPSO) facility (Ichthys Venturer) while the gases will be transported via the 890-kilometer long Gas Export Pipeline (GEP) to the onshore gas liquefaction plant at Darwin in Australia’s Northern Territory. The gas will be exported to an onshore Liquefied Natural Gas (LNG) plant which will produce 8.9 million tons of LNG per year for supplying the Asian market, and approximately 1.65 million tons of liquefied petroleum gas (LPG) per year as well as an additional 15,000 barrels of condensate a day. Inpex said that it expects to begin the shipment of products towards the end of the first half of the current fiscal year. “The start-up of production on Ichthys is a major achievement. Ichthys will be an important addition to Total’s portfolio in the fast growing LNG market and will also contribute to the Group’s production and cash flow growth in the coming years”, commented Arnaud Breuillac, President Exploration & Production at Total. The Ichthys LNG Project is led by Inpex (Operator, participating interest: 62.245 per cent) alongside major partner Total (participating interest: 30 per cent) and the Australian subsidiaries of CPC Corporation, Taiwan (participating interest: 2.625 per cent), Tokyo Gas (participating interest: 1.575 per cent), Osaka Gas (participating interest: 1.2 per cent), Kansai Electric Power (participating interest: 1.2 per cent), JERA (participating interest: 0.735 per cent) and Toho Gas (participating interest: 0.42 per cent).

SOPAN to Provide One of the Most Eco- friendly Enhanced Oil Recovery Solutions in India Ties up with Titan Oil Recovery to provide this Solution to the Indian Market SOPAN, an experienced player in the Oil & Gas sector in India, has signed a Service Agreement with Titan Oil Recovery Inc., a US based veteran in the field of Enhanced Oil Recovery with deployments across four continents, for providing Organic Oil Recovery (OOR) solutions to the Indian Oil Production Industry. The OOR process involves stimulating the growth of specific species of indigenous microbes within the producing reservoirs, which have the effect of reducing the physical size of trapped oil droplets, greatly enhancing production rates at a fraction of the cost of alternative Enhanced Oil Recovery (EOR) technologies. With no separate setup required to execute, the OOR process increases ultimate oil recovery substantially. With a total of over 300 production well implementations of OOR by Titan, multiple customer authored SPE papers record average oil production increases

within the range of 25% to 700%, and costs per incremental barrel of US $6-$15. Statistically, an average increase of 92% has been observed upon the application of the Titan process across over 300 well application globally. This makes the technology suitable during both high and low Crude Oil rates. In addition, the process requires no topside modification offshore, therefore eliminating any need for incremental Capex. Mr. C. V. Kadvekar, Managing Director of SOPAN said, “A sizeable part of the current domestic production of oil comes from mature fields, most of which are showing signs of production decline, if not on a decline already. As a result, the government is taking special interest in boosting the growth of production from such mature & ageing fields and we expect a lot of activity in this space in the coming years. This OOR technology will provide a great and cost effective solution to the oil extraction process in India.” Mr. Kenneth Gerbino, Chairman and Founder of Titan Oil Recovery Inc. added, “We are pleased to team up with SOPAN, a well-recognized and admired oil service company in India. The Titan Process when adopted by the Indian oil industry could have a major impact on reducing India’s dependence on imports.” This next generation oil recovery technology, with negligible Capex requirement, low cost and organic nature of the process requiring no modification in the production process & methodology is set to revolutionize EOR technology in India.

Dr Ravi Mehrotra Receives Lifetime Achievement Award at Seatrade 30th Anniversary Awards Event Dr Ravi Mehrotra CBE, Chairman of Foresight Group International Ltd., was presented with a lifetime achievement award by Mr Chris Hayman (Chairman, Seatrades) at the Seatrades 30th Anniversary Award Ceremony held at the Landmark, London on June 29th. The award recognises recipients who have made a significant and lasting contribution to shipping and the maritime industry. In making the Award Mr Hayman stated that “the award goes to a man who has achieved a very great deal across a number of fields, not just shipping” and highlighted that “his accomplishments had spanned drilling, the high-end restaurant business, farming, shoe manufacture & retailing, as well as running a maritime & offshore training institute in the grounds of his former family home city in a landlocked state of one of the world’s most populous countries”. This award arrives shortly after Vivekanand 2 (a drilling rig from Foresight Offshore Drilling formerly Hallworthy Shipping Limited S.A.) was announced as “THE BEST PERFORMING RIG OF 2017/18” for ONGC (Oil & Natural Gas Corporation Limited). The Rig was selected during the recent JRM (Joint Review Meeting) chaired by the Chairman & Managing Director of ONGC from amongst 38 offshore jack-up drilling rigs working in the Mumbai offshore area. Dr Mehrotra has also recently announced that he is embarking on a Corporate Social Responsibility initiative with the Indian Government to undertake the cleansing of the holy river Ganges and landscaping of its banks on a stretch passing through his home city of Kanpur.

Offshore World | 37 | June-July 2018

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NEWS

Inpex starts production at LNG Ichthy project

NEWS

ONGC conferred with INFRA Icon Award in the ‘Global Energy’ category ONGC conferred with INFRA Icon Award in the ‘Global Energy’ category ONGC, the 2nd largest E&P company in the world, has been conferred with INFRA Icon Award in the ‘Global Energy’ category at the mid-day INFRA Icons Awards 2018. The award, on behalf of Chairman & Managing Director, ONGC was received on July 27, 2018 at Mumbai by Executive Director – Head Regional Office, ONGC Mumbai, S Gopinath. The award was presented by Additional Metropolitan Commissioner, MMRDA, Pravin Darare. With the theme for the evening being - Smart cities envisages to take infrastructure development to a next level (Infrastructure 2022), the event was attended by dignitaries and industry veterans from key infrastructure sectors such as Construction, Ports, Power, Oil & Gas, Steel, Civil aviation, Road transport etc. along with other stakeholders in the ecosystem such as policymakers, financial institutions, industry regulatory bodies amongst others.ONGC has received the top corporate level award in recognition of its valuable contribution which has not only supported but also upgraded the country as a whole. During the panel discussion, ED-HRO, ONGC, S Gopinath remarked that to realize the Hon’ble PM’s vision of 10% hydrocarbon import reduction by 2022, along with enhancement in domestic energy production, capacity building in major infrastructure development like roads etc. has to play a huge role to enable energy savings. At the same time, it’s important to reduce our carbon footprints, he added. Sharing about ONGC’s effor ts towards reducing its Carbon Footprints, he informed the audience that the CMD of ONGC took a pledge in the presence of Hon’ble PM to completely do away with single use plastic within the organization and effor ts are already afoot in this direction. He also shared about the successful implementation of enterprise wide paperless project, where by all the file work is being done digitally, saving on huge quantities of paper usage and helping ONGC reduce its carbon footprint. The “INFRA Icons”, is an initiative by mid-day, designed to bring to the forefront the change makers and trend setters associated with the infrastructure of India.The award recognizes the exemplar y per formance in the corporate world and is felicitating the top companies across various sectors. The award is in recognition of ONGC as one of the most distinguished and admirable icons in the Corporate World, based on performance and best– practices across the industry

MRPL wins BML Munjal Award MRPL wins BML Munjal award for Business Excellence through Learning and Development Mangaluru. April 19, 2018 : MRPL won the prestigious BML Munjal Award for Business Excellence through Learning and Development. The 13th edition of this Award was given away on 19 th April 2018 at a grand function in New Delhi by Former President Shri Pranab Mukherjee. MRPL won the Runner up trophy in the PSU Manufacturing category. The award www.oswindia.com

was received by Shri B H V Prasad, GGM(HR) on behalf of Team MRPL. This HR award is unique as there is a stringent four stage due process to select the winners with eminent personalities of the Corporate India serving as the jurors. The Award recognises HR departments in Corporate that follow robust people processes that deliver a positive difference to business.

BPCL Selects AspenTech Software for Asset Optimization and Operational Excellence Last year, the Government of India conferred BPCL with Maharatna status. The company operates through two segments: Downstream petroleum (refining and marketing of petroleum products), and Exploration and Production of Hydrocarbons (E&P). The company’s refineries are located at: Mumbai (Maharashtra), Kochi (Kerala), Numaligarh (Assam), and Bina (Madhya Pradesh). Its marketing infrastructure includes network of installations, depots, retail outlets, aviation service stations, and LPG distributors. The oil and gas sector faces an increasingly complex environment, companies need to be innovative in adopting new business models and partnerships. Leading players, such as BPCL, need to have a resilient strategy to protect against price dips and adopt digital transformation in an astute manner to improve operational performance. Considering all these factors, BPCL began scouting for a one-stop solution provider that could help drive business sustainability and increase profitability by maximizing asset performance across BPCL Group Refineries. Earlier on, BPCL had also deployed AspenTech solutions in pursuit of energy management and asset optimization at their Mumbai refinery. Following a successful deployment, BPCL proceeded to standardize on AspenTech software solutions. The solutions include Aspen HYSYS Petroleum Refining; Aspen Exchanger Design & Rating; Aspen Economic Evaluation; Aspen Energy Analyzer; Aspen DMC3; Aspen InfoPlus.21; aspenONE Process Explorer; Aspen PIMS-AO; Aspen Supply Chain Planner; Aspen Tank and Operations Manager; and Aspen Operations Reconciliation and Accounting. Centralized control and a single point of contact and accountability will help the company to achieve operational excellence and gain competitive advantage. AspenTech’s integrated solutions across design and operations will help BPCL maximize profitability, increase return on capital, and improve complex manufacturing and operating scenarios. With aspenONE software, organizations can run to the limits of performance and achieve optimal financial return over the entire asset lifecycle without compromising safety, reliability or regulatory compliance. In partnering with AspenTech, BPCL can capitalize on digital transformation to reduce costs, maximize growth and achieve sustainable operations via operational excellence. With this deployment, BPCL is well positioned to support energy needs and emissions standards in India.

Offshore World | 38 | June-July 2018

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PRODUCTS Measuring Technique for Cold & Telescopic Lip Dock Levellers Warm Water Telescopic lip dock levellers In India, every person uses on an average 155 litres of water a day compared to developing countries that uses 20 litres. Toshniwal provides a comprehensive residential meter portfolio to meet the world’s water utility requirements. Toshniwal’s Series continues to be in the water industry standards. Their quiet, rugged and reliable apartment and domestic water meters achieve ultra-low flow measurement and meets or exceeds all standards. The ISO Standard assures you that Toshniwal has achieved the highest possible standards for measuring accuracy and reliability for both manufacturing and customer service quality (approved in 16 countries) meter with 8 number registered allowing precise and easy reading in m 3 and litres, horizontal and vertical installation; rising and down pipes meter head completely turnable; and dry type single jet impeller with magnetic drive. For details contact: Toshniwal Hyvac Pvt Ltd 267 Kilpauk Garden Road Chennai 600 010 Tel: 044-26445626, 26448983 E-mail: sales@toshniwal.net

are more flexible type of dock leveller which generally proves more versatile in being suited to a wider range of vehicle loading bay applications. Telescopic lip dock levellers are ideal for connecting vehicles unable to drive near sea containers, side loading railway wagons, etc. Once the platform has been raised, the telescopic lip 500 mm or 1,000 mm long is continuously extended to the required length and is then lowered on the vehicle deck. The truck can be loaded right up to the very last centimeter as the telescopic lip can be positioned with pinpoint accuracy. For details contact: Gandhi Automations Pvt Ltd Chawda Commercial Centre, Link Road Malad (W), Mumbai 400 064 Tel: 022-66720200, 66720300 Fax: 91-022-66720201 E-mail: sales@geapl.co.in

RAS Pulsed-Neutron Tool Probe offers the Reservoir Analysis System (RAS) pulsed-neutron tool, a three-detector system that uses sigma and carbon-oxygen (C/O) techniques to measure reservoir fluid saturation of oil, water and gas. The system quantifies water and oil saturation, water flow velocity, and detects gas and porosity. The RAS pulsed-neutron tool was developed by Hunter Well Science, an independent alternative specialist and a subsidiary of Probe, to measure reservoir fluid saturation of oil, water and gas. It operates in three basic modes: sigma - water saturation detected via thermal neutron decay; C/O - oil saturation detected with gamma spectroscopy; and water flow - water velocity from oxygen activation In addition, in sigma mode, the three-detector array can be used to measure gas saturation. For wells with limited data, the tool can make standalone porosity and lithology measurements. By using modern, ruggedized electronics, the pulsed-neutron tool has been streamlined into a compact-robust device. The tool and telemetry-gamma ray casing collar locator (CCL) together constitute the shortest reservoir analysis tool string in the industry, measuring a combined 16.9 feet (5.14 m). At the center of the pulsed-neutron tool is a rugged neutron generator that operates in temperatures as high as 320°F (160°C) and has a typical service life of 1,000 hours, nearly double the lifespan of many other reservoir analysis tools. It is used in a variety of applications, particularly in casedhole and openhole completions in surface read-out and memory-operating modes, on conventional tubing, e-Line, e-Coil, conductor and conventional slickline. To help operators gather definitive saturation data, the pulsed-neutron tool is effective for the following applications: saturation logging of water, oil and gas; time-lapse reservoir monitoring; contact logging and time lapse contact logging; oxygen activation (water flow) to determine water phase velocity; openhole emulation; and wellbore performance (in combination with production logging).The pulsed-neutron tool is offered for purchase to oilfield service companies, NOC’s and IOC’s. For details contact: Probe 6824 N Sam Houston Pky W Houston, TX 77064, U.S.A. Tel: +1 281 987 2244 E-mail: federico.casavantes@probe1.com www.oswindia.com

Offshore World | 40 | June-July 2018

PRODUCTS Flow Sensors

Leak-free High-pressure Compressor

VSE supplies customer specific flow sensors of the highest quality and within shortest development times. Bedaflow provides exceptional solutions tailored to the client's individual requirements in a wide range of materials, eg, steel, SS, titanium, aluminium as well as in bronze materials.It finds application in hydraulics, offshore technology and

The Tornado WP3325 B3-5 BasBooster-R from Sauer Compressors is an oil-lubricated compressor. It achieves a final pressure of 400 bar.g and a suction pressure of up to 5 bar.g. With a leakrate of only 0.1 mbar x l/s, this range of models enables the compression of valuable gases like helium with virtually no losses.

process automotive control. For details contact: Bedaflow Systems Pvt Ltd W-7, Sector-11 Noida, Uttar Pradesh 201 301 Tel: 0120-43299 - 90 Fax: 91-0120-43299 - 20 E-mail: info@bedaflow.com

For details contact: J P Sauer & Sohn Maschinenbau GmbH Brauner Berg 15 24159 Kiel, Germany Tel: +49 431 3940-0 E-mail: William.koester@sauercompressors.de

Level Indicators Visual level indicators combine up to three functions in one instrument: level indicator, level switch and level transmitter. The display that can be read even over large distances works without energy and automatically as a result of the physical law of liquids in communicating vessels. The WEKA visual level indicators are characterized by their compact design and the wide range of applications. Operating pressures can range from a vacuum up to 500 bar as well as calculation pressures for the float standpipe up to the nominal pressure PN 630. Liquid densities >0.27 g/cm 3 as well as a temperature range from 77 K to 673 K (-196°C to 400°C) allow use in applications for cryogenic liquid gases as well as in water hydraulics and steam boilers. Hermetically sealed floats for condensing media are available up to a max operating pressure of 320 bar. Flexibility through choice of suitable materials - standard materials: 316/316L 1.4435/1.4404, Group A4 stainless austenitic steel. Other possible stainless austenitic steels: 304/304L 1.4301/1.4306, 1.4571, 321, 1.4541. The WEKA visual level indicator is ideal for the commissioning of systems. The display works without energy and automatically as a result of the physical law of liquids in communicating vessels. Independent of a controller - and thus also independent in the event of a power supply failure - visual level indication on site is ensured. The wide, red- and silver-colored flag indicator system is easily and clearly readable, even from over large distances. The fully transparent flag indicator system made of polycarbonate (PC) also ensures readability from the side. The liquids, which are not always unproblematic and sometimes also hazardous, are safely enclosed in the dense and pressure-tight float standpipe and separated from the indicator. As described, WEKA visual level indicators offer the ideal solution for almost all operating conditions. For most applications, you will find a suitable device from their standard program. Again and again, however, customized solutions are also required for special operating conditions. Many designs can, eg, also be used in hazardous areas according to ATEX or IECEx (ATEX is a widely used synonym for the ATEX guidelines of the European Union). The designation ATEX is derived from the French abbreviation for atmosphere explosibles. Toshiwal’s instruments can thus also be used in potentially explosive atmospheres. It finds application in explosion-proof plants, mechanical and plant engineering, water management, ship building, energy, space and research. For details contact Toshniwal Hyvac Pvt Ltd 267 Kilpauk Garden Road Chennai 600 010 Tel: 044-26445626, 26448983 E-mail: sales@toshniwal.net Offshore World | 41 | June-July 2018

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PRODUCTS Edge-of-Dock Levellers

Oil-freeHigh-pressureCompressor

Edge-of-Dock leveller is developed in compliance with the latest European Safety Standard EN 1398. It has a capacity of 6,000 kg and is suitable for use with all types of loading equipment from manual pallet trucks to fork trucks. The open hinge lip construction carries a lifetime guarantee and has a solid-welded connection between the lip plate and the beams under the deck to ensure the lip angle of 7.5o will be maintained. It is extremely important when loading/unloading vehicles with bed heights above dock level, to ensure that the lip always lays flat on the vehicle floor to avoid the tripping hazard.

The HAUG.Sirius HP 450 is the first compressor to combine Sauer’s extensive know-how in high-pressure applications and HAUG Sauer’s expertise in manufacturing oil-free solutions. The result is a powerful highpressure compressor that is entirely oil-free to ensure excellent gas purity. The hermetically gas-tight construction achieves extremely low leak rates and enables 4-stage compression of almost any gas. With a volume flow rate of 60 Nm3/h, the compressor operates at a suction pressure of 5 bar.g and a final pressure of 450 bar.g.

For details contact: Gandhi Automations Pvt Ltd Chawda Commercial Centre, Link Road Malad (W), Mumbai 400 064 Tel: 022-66720200, 66720300, Fax: 91-022-66720201 E-mail: sales@geapl.co.in

For details contact: J P Sauer & Sohn Maschinenbau GmbH Brauner Berg 15 24159 Kiel, Germany Tel: +49 431 3940-0 E-mail: William.koester@sauercompressors.de

Pumps and Compressors Blackmer offers STX Series transport pumps ideal for loading and unloading corrosive and noncorrosive liquids – sulfonic acids, specialty chemicals, solvents, latex paints, liquid sugars and vegetable oils – that are not compatible for use with cast iron pumps. These pumps offer the best combined characteristics of sustained high-level performance, energy efficiency, trouble-free operation and low maintenance costs. Blackmer ML Series pumps are ideal for liquid-terminal operations that require high-capacity product transfer, top or bottom loading/unloading and blending at the rack. ML Series pumps offer tremendous self-priming and high-suction capabilities that enable them to clear tanks of product more effectively and efficiently than competitive models. ML pumps can handle fluid viscosities from 30 to 500,000 ssu (1.0 to 108,000 cS) with flow rates up to 600 gpm (136 m 3/h) and at operating temperatures as high as 400°F (206°C). S Series screw pumps with or without external timing gears and bearings are self-priming double-ended positive displacement pumps that offer outstanding performance in the most demanding liquid-storage terminal applications. Blackmer twin and triple screw designs provide complete axial balancing of the rotating screws and their timing technologies eliminate metal-to-metal contact with the pump. S Series pumps are also ATEX-certified for use in explosive or dangerous environments. Blackmer HD Series reciprocating gas compressors provide quiet, efficient transfer of a wide range of liquefied gases. HD Series compressors also have been designed to handle the vapour recovery of gases that are common in terminal applications. The vapour recovery aspect of this application captures vapours before they are released in the environment, allowing terminals to be more environmentally responsible and compliant while ensuring the most complete product transfer possible. For details contact: Dover India Pvt Ltd - PSG 40 Poonamallee By-pass Saneerkuppam, Chennai 600 056 Tel: 044-26271020, 26271023 E-mail: sales@psgindia@psgdover.com www.oswindia.com

Offshore World | 42 | June-July 2018

PRODUCTS Openwell Submersible Pumpsets High-pressure Pumps CRI openwell submersible pumpsets CSM/CV/CVH Series are ideally suitable for openwells or tanks where a wide fluctuation of water level occur. This works under water and rest at the bottom of the well. Prime mover is rewindable, water-cooled motor. Specially designed water lubricated bearings are used to withstand axial thrust loads with minimum wear and tear. The stator is wound with special water proof synthetic film insulated copper winding wires and made up of low watt-loss silicon steel laminations assembled under pressure and rigidly locked. Motor sealing is made by polymers, O-rings, oil seals and sand guard to avoid ingress of well water/sand into the motor. Pressure equalizing rubber diaphragm is provided to guard the pressure and volume variation of water inside motor. Motor must be filled with clear, cold, drinking water as detailed in their operatorâ&#x20AC;&#x2122;s manual. Three-phase motor requires an adequate motor protection control panel. For details contact: CRI Pumps Pvt Ltd 7/46-1 Keeranatham Road Saravanampatty, Coimbatore, Tamil Nadu 641 035 Tel: 0422-3027000 Fax: 91-0422-3027005 E-mail: corp@cripumps.com

HPP is a Cornet SpA brand specialised in the design and construction of plunger pumps for water, made even better thanks to its technological expertise and further boosted by modern day technologies. This means the company is able to offer a wide range of products to meet requirements that go from 50 to 400-KW with pressure up to 2,800-bar. HPP pumps are manufactured using the most modern technologies both as regard to the materials used machining and mechanical operation and heat treatments. Comet is also able to provide a wide range of accessories, suitable for the specific need of the single user. Professionalism and research make it a dynamic modern company intent on tackling and resolving the problems of a fast-evolving market. For details contact: Powerjet Engineering Gala No: 108, Building No: 7 Blue Mount Work Station Premises CSH Ltd Sativali Road, Village Waliv Nr Parle Global Technologies, Vasai (E) Dist: Thane, Maharashtra 401 208 Tel: 0250-6454169, 6580963 E-mail: info@powerjetengineering.com sales@powerjetengineering.com

Ultrasonic Sensors for Measuring Storm Water Runoff Ultrasonic level transmitters, on the other hand, are a widely recognized alternative to hydrostatic pressure level measurement for storm water applications. AMETEK Drexelbrookâ&#x20AC;&#x2122;s USonic-R level transmitter is a perfect choice for storm water measurement. USonic-R is FM and ATEX approved. It has a patented SmartGain feature that eliminates the issue of false echoes. SmartGain quickly recognizes pumping station obstructions, such as ladders and pipes in sewage wells, helping ensure accurate level readings. USonic-R picks up data from two separate ultrasonic sensors placed at different locations. Data is logged, flow calculated from weirs or flumes and signals can be sent to emergency pumps. The transmitter also can deliver crucial data, showing the state of sewage wells, basins, drilling mud and fluid in tanks. USonic-R incorporates a converter and a datalogger. Data is delivered either as a 4-20 mA or Modbus signal, which allows for easy integration into the most common SCADA systems. The instrument works seamlessly with RTUs, simple pump controls or PLCs. This is important for remote installations in which intelligent or autonomously operation is required for level measurement, flow calculation or pump activation when necessary. The versatile USonic-R even allows two individual ultrasonic sensors to be connected, enabling users to calculate the sum or differential of pumped volume by measuring each side of two basin walls. The unit is weather proof, IP66/NEMA6-P rated and UV protected, meaning that, in general, the device requires no additional protection. Drexelbrook offers a full range of level measurement solutions, including RF Admittance/Capacitance, TDR/GWR, Radar, Ultrasonic, Magnetostrictive, Hydrostatic, Vibration, Conductive and Float Devices. For details contact: Drexelbrook (A Unit of AMETEK, Inc) 205 Keith Valley Road Horsham, PA 19044, U.S.A. Tel: 215-674-1234 Fax: 215-674-2731 E-mail: jim.mckinley@ametek.com / drexelbrook.info@ametek.com Offshore World | 43 | June-July 2018

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PRODUCTS Gas Analyzer

External Gear Pump DARTec

LYONS, CO – AMETEK MOCON’s Baseline 9100 Gas Analyzer performs the analysis of residual solvents in air p ethanol, isopropanol (IPA) and acetone—that are used in semiconductor cleanroom environments, ie, solvent stations. During semiconductor fabrication processes, volatile organic compounds (VOCs) are emitted primarily from diffusion and cleaning during wet-etching processes. The residual presence of these solvents can be detrimental to production yields and to worker health. MOCON’s Baseline 9100 Gas Analyzer combines the selectivity of gas chromatography with the sensitivity of a photo ionization detector (PID). The analysis provides an interference free response to ethanol (if desired), IPA, and acetone in air no preconcentration necessary. Competitive analytical approaches that require preconcentration exhibit much longer analysis times, are much more costly, more complex, and suffer from poor reproducibility. The solvents are detected and accurately quantified to sub-ppb levels in under 3 minutes with ethanol producing no interference. The instrument is sensitive to below 5 ppb for both IPA and acetone employing MOCON’s standard Baseline PID, and <0.1 ppb using MOCON’s high sensitivity Baseline PID.

The DARTec gear pump (DosingAutomation-Robot-Technology) was specifically designed for applications that depend on the highest level of repetition and dispensing precision. The 700 gram lightweight pump basically comprises a front plate, a center plate, two bear plates and a rear plate, the pairs of gear, a pump shaft and a drive shaft which are guided in high-precision bearings. To achieve the greatest precision, reproducibility and best possible total efficiency, the clearances inside the pump are adapted depending on the medium to be delivered, the differential pressure and the viscosity. Thus, high reproducible volumetric efficiencies can be achieved. Due to the corrosive wear, the use of coatings and special materials suitable to the application are used, leading to a technically ideal and cost-effective as well as optimum life time. It finds application in handling equipment and robots, process engineering and technology, mobile communication technology, automotive industry, mechanical engineering and plant construction, electronic industry, and plastics and wood processing.

For details contact: AMETEK Inc 1100 Cassatt Road, Berwyn, Pennsylvania 19312, U.S.A. E-mail: info.baseline@ametek.com

For details contact: Bedaflow Systems Pvt Ltd W-7, Sector-11 Noida, Uttar Pradesh 201 301 Tel: 0120-43299 - 90 Fax: 91-0120-43299 - 20 E-mail: info@bedaflow.com

iCUE Digital Anomaly Detection App Clarus Subsea Integrity offers the iCUE Digital Anomaly Detection App, technology that provides rapid, accurate detection of anomalies by reviewing inspection video footage of subsea assets. By using the App to assess footage of subsea risers, pipelines or moorings, for example, operators immediately receive a more accurate account of conditions that might otherwise go undetected. In addition, the speed at which it analyzes footage and identifies anomalies is at least 10 times faster than manual review, which is significant when assessing whether an asset is fit for continued service or requires attention. To achieve this, the App automatically carries out an engineering assessment of the inspection footage. The App is based on machine learning, and draws upon image analysis technologies. Clarus trained it with a machine-learning algorithm to accurately qualify an anomaly by using a structured data set of positive examples of anomalies. Integrity managers can also use it to trend anomalies from multiple inspections conducted on an individual asset field life. This is useful when considering a possible extension for an asset that is approaching the end of its original design life. Armed with more accurate detection reports, they are fully apprised as to the extent, nature and severity of anomalies to determine whether they must be addressed immediately, require ongoing monitoring or remediation before qualifying the asset for life extension. For details contact: Clarus Subsea Integrity, Inc 15990 North Barkers Landing, Suite 200 Houston, Texas 77079, U.S.A. Tel: +1 832 664 7622 E-mail: dharmik.vadel@clarusintegrity.com www.oswindia.com

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PRODUCTS Sampling Valves

Openwell Submersible Pumpset

Cipriani Harrison offers various types of sampling valves for different applications. The 33 Series is machined from SS304L or SS-316L, has no seats or seals and works by a simple quarter turn handle. The 34 Series sample valve which is machined from SS-304L or SS-316L bar stock is completely self-draining and has PTFE seat and FDA silicone seals. The 33 Series is available with 3/8” or ½” MNPT and 1” clamp connections and the 34 Series comes with ½” MNPT as well as ½” or 1” clamp connections. The 34 Series has a leak detect port that indicates when a seal has worn out. The 34 Series is available with ½” SIP flushport as optional. The 35 Series sample valve is machined from SS-316L bar stock. Provides a quick and easy way to bleed or drain a system. Floating PTFE O-ring ensures positive sealing and cleanability. The 35 Series is available with ½” and 1” sanitary clamp connections.

CRI openwell submersible pumpsets - CSS/CVS/LTK Series are ideally suitable for openwells or tanks where a wide fluctuation of water level occur. This works under water and rest at the bottom of the well or tank. Hence, suction and priming problem will not arise. The optimal design of impellers and diffusers enables the best possible hydraulic efficiency. Motor sealing is made by polymers, O-rings, oil seals and sand guard to avoid ingress of well-water/sand into the motor. Pressure equalizing rubber diaphragm is provided to guard the pressure and volume variation of water inside motor. Motor must be filled with clear, cold, drinking water as detailed in their operator’s manual. Three-phase motor requires an adequate motor protection control panel.

For details contact: Cipriani Harrison Valves Pvt Ltd Sub Plot No: 2, B/s Maregin Ipex Ltd Nr Phase IV, GIDC Estate V U Nager, Anand, Gujarat 388 121 Tel: 02692-235082, 235192 Fax: 91-02692-236385 E-mail: info@harrisonengineers.com

For details contact: CRI Pumps Pvt Ltd 7/46-1 Keeranatham Road Saravanampatty Coimbatore, Tamil Nadu 641 035 Tel: 0422-3027000 Fax: 91-0422-3027005 E-mail: corp@cripumps.com

Membrane Contactors Liqui-Cel membrane contactors are offered by Membrana, USA, makers of liquid degasification contactors. Liqui-Cel membrane contactors are widely used for removal of dissolved gases such as oxygen, carbon dioxide, nitrogen and ammonia in aqueous solution. Membrane contactors are typically shell-and-tube device containing microporous hydrophobic, hollow fibres. The MoC of hollow-fibre is polypropylene having internal dia 200-220 microns, outer dia 300 microns and having an average pore size of 0.03 microns. Water is passed on outside of the membrane (shell side) and a gas is passed inside of the membrane (lumen side). Since the membrane is manufactured using a hydrophobic material and the pores are small, water does not easily pass through the pores. The membrane essentially acts as a support between the gas and liquid phases and allows them to interface at the pores. Gases, however, freely pass through the pores on a molecular level, sweep gas as air or nitrogen and/ or vacuum is applied inside the fiber which results in reducing the partial pressure of the gas to be removed. The water leaving the membrane contactor will be degassed. It finds application in boiler feed water (oxygen removal); pharma (carbon dioxide removal); removal of non-condensable gases in pure steam generator; power and microelectronics (oxygen and carbon dioxide removal); beverage (carbon dioxide injection and oxygen removal); humidification of gases in pharma and process industries; and printing (degassing of inks and coatings). For details contact: Evergreen Technologies Pvt Ltd 3-D, Maker Bhavan-2, 18 New Marine Lines Mumbai 400 020 Tel: 022-22012461, 22012706, 61566969 Fax: 91-022-22010024 E-mail: info@evergreenindia.com Offshore World | 45 | June-July 2018

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PRODUCTS Spray Balls

External Gear Pump

Ci p r i a n i H a r r i s o n’s f i xe d / s t a t i c s p r a y b a l l s a re m a d e f ro m S S 3 1 6 L a re h i g h l y p o l i s h e d a n d h a ve 2 . 5 ” a n d 3 . 5 ” d i a b a l l s. Th e y c o m e s t a n d a rd w i t h a slip-pin connection for 1” a n d 1 . 5 ” s i ze t u b i n g. Th e y a re a v a i l a b l e i n f o u r d i f f e re n t s p r a y p a t te r n s f o r c l e a n i n g a l l t y p e s o f t a n k s a n d p ro c e s s e q u i p m e n t.

ZPD gear pumps were specifically designed for dosing applications, oil hydraulics and process technology. Due to different t ypes of toothing and modules, the medium is being delivered with low pulsation, so that exac t dosing requirements can be realized the best possible way. By doing so, volumetric efficienc y values of over 90% are achieved with charac teristic cur ves largely independent of the operating point. That means that the dosing quantit y can be set precisely through the pump speed.

Cipriani Harrison’s rotary spray balls are made from SS-316L and are highly polished and are suitable for 1” and 1.5” ISO/DIN pipe. Four different spray patterns are available for cleaning all types of vessels. For details contact: Cipriani Harrison Valves Pvt Ltd Sub Plot No: 2, B/s Maregin Ipex Ltd Nr Phase IV, GIDC Estate V U Nager, Anand, Gujarat 388 121 Tel: 02692-235082, 235192 Fax: 91-02692-236385 E-mail: info@harrisonengineers.com

It finds application in dosing technology. process engineering and technology. lubricating oil supply and system technology. For details contact: Bedaflow Systems Pvt Ltd W-7, Sector-11 Noida, Uttar Pradesh 201 301 Tel: 0120-43299 - 90 Fax: 91-0120-43299 - 20 E-mail: info@bedaflow.com

Suspended Pumps with Hydraulic System The Estigia Type Series extends the KSB SE & Co KGaA, Frankenthal, product portfolio for the chemical and petrochemical industries and other applications. The low-pressure suspended pumps are designed for vertical wet installation in a closed tank under atmospheric pressure. For the installation depth, various lengths ranging from a minimum of 852 mm to a max of 6,402 mm are available and three discharge pipe dia can be selected for each pump size. Given the vertical design, the pumps only require little space. When the immersion depth exceeds 2,400 mm, a special design element between the support column sections and the discharge pipe makes for significantly reduced vibrations. The casing cover of the pump is fitted with a product-lubricated plain bearing made of highgrade, wear-resistant silicon carbide. The pump set is easy to install and dismantle with its integrated cover plate serving as the tank cover. The material variants on offer are cast iron, stainless steel and duplex steel. Replaceable casing wear rings prevent possible wear on casing and impeller. The Estigia Type Series is characterised by a high efficiency and low operating costs. The pump set can be supplied with shaft bearings lubricated by the fluid handled, an external liquid or an electric grease pump. A so-called cantilever design is also available. This version is designed to ISO 5199, with flexible coupling and grease-lubricated rolling element bearings arranged outside the fluid handled. The pump is suitable for fluid temperatures of -30°C to +100°C. It can be driven by variable speed and fixed speed electric motors, with or without ATEX approval. For details contact: KSB Pumps Ltd Mumbai-Pune Road Pune, Maharashtra 411 018 Tel: 020-27101231 Fax: 91-020-27426000 E-mail: Yagnesh.Buch@ksb.com www.oswindia.com

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PRODUCTS Slim Line Ball Valves

Bearing Isolators

Cipriani Harrisonâ&#x20AC;&#x2122;s slim line ball valves are made from forged SS-304L and SS-316L, are highly polished and come standard with TFM-PTFE seats and FDA EPDM O-rings. The 2 piece design provides a compact and economical solution while maintaining a full por t design, as well as being fully drainable. Available in size 1-4â&#x20AC;? with sanitar y clamp, Butt-weld or I-line end connections. They are available with or without purge por ts and either manually or pneumatically controlled.

Klozure bearing isolators feature labyrinth design to prevent ingress of contaminants. Key produc ts include MICRO-TEC II and GUARDIAN, both of which employ a patented cam lock design and engineered unitizing ring. These and other Klozure bearing isolators are used extensively in the chemical, pulp and paper, hydrocarbon processing, power generation and many other industries. SGi bearing isolator unlike regular analogue drives, drives induce shaft voltage that can damage and cause bearings to fail. Developed to provide electrical insulation. For details contact: Garlock India Pvt Ltd Plot No: 21, "S" Block, MIDC Bhosari, Pune Maharashtra 411 026 Tel: 020-30616608 Fax: 91-020-30616699 E-mail: sales.india@garlock.com

For details contact: Cipriani Harrison Valves Pvt Ltd Sub Plot No: 2, B/s Margin Impex Ltd Nr Phase IV, GIDC Estate V U Nager, Anand, Gujarat 388 121 Tel: 02692-235082, 234182 Fax: 91-02692-236385 E-mail: info@harrisonengineers.co

Solid Liquid Separation SAP Filter offers special filters for chemical and pharma applications in API for separation of activated charcoal or solids produced during the reaction of the reactants. Also, their Microbac candle filter is suitable for catalyst separation and recycles in any reactions including hydrogenation. Candles are fabricated in pipes of equal dia and assembled together in such a way that it results into a candle which is dressed with anti-static cloth of suitable material through which filtration is affec ted. After scavenging the filter, the cake is washed insitu or displacement washing is another option to restric t the use of adequate ML (mother liquor). After washing the cake the filter is scavenged again and cake is discharged either dr y or in slurr y condition. Most suitable for ac tivated carbon or carbon suppor ted catalysts. For batch filtration SAP Filter offer zero hold-up sparkler filters of various sizes. The MoC can be any stainless steel or high alloys like 904L, Hastelloy, Inconel, etc. The zero hold-up filters are available in PP, PVDF and Teflon. Vessel-lined with PP, PVDF or Teflon and cartridge fabricated from solid block. For details contact: SAP Filter Pvt Ltd Plot No: A-5, Sector 1 The Vasai Taluka Indl Co-op Estate Ltd Goraipada, Vasai (E) Palghar, Maharashtra 401 208 E-mail: info@sapfilter.com sapfilters@gmail.com Offshore World | 47 | June-July 2018

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PRODUCTS Process Analyzer

V Cone Flow Meters

The 202X Process Analyzer family comes in three basic configurations, covering several market needs. The 2026 Titrolyzer is suitable for titrimetric, ion selective or pH measurements. The 2029 Process Photometer performs photometric absorption measurements in the visible light range. A 7” full-colour touchscreen shows trend graphs and allows easy access to your data. These process analyzers are especially suitable for analysis in the chemical, petrochemical, semiconductor, food and beverage, potable water, and environmental branches. Metrohm Process Analytics can offer process analyzers which are configured for each specific application challenge. Sample dilution, extra reagents, or even another sample stream can be added with the addition of peristaltic pumps in the modular wet part. Strict separation of wet part and electronics ensures safe operation in harsh environments. The electronics part is housed within non-corrosive polyester-coated stainless steel. With an Ingress Protection rating 66, the analyzer is guaranteed to be dust and water-tight. Metrohm Process Analytics provides virtually any sample preconditioning system, such as cooling or heating, pressure reduction, degassing, filtration and more. Information including results, remote control and status info, can be communicated through discrete I/O (ie, analog outputs digital in/outputs), MODbus TCP/IP (Ethernet), or RTU (RS485) communication. Remote control is possible through VNC (Ethernet). Results can also export to USB.

V-Cone flow meter is an advanced differential pressure instrument, which is ideal for use with liquid, steam or gas media in rugged conditions where accuracy, low maintenance and cost are important. The V-Cone is designed for today’s most challenging oil/gas production, chemical, food and beverage, plastics, pharma, district HVAC, textile, power, and water and wastewater applications. It combines exceptional performance, low maintenance and long life for superior value. Follow International Manufacturing Standards. ATEX variants is available. It is useful in tight-fit and retrofit installations. Features line size range 0.5” to 120” or larger; accuracy +/-0.5% and repeatability +/-0.1%; patented differential pressure flow meter technology; remote monitoring; V-Cone meters have no moving parts and their unique design enables the meter to work perfectly even when the measuring media has particulates such as sand and dust. The patented cone design gives the V-Cone the ability to work with short lengths of pipes in front and after the meter; helium custody transfer; compressor monitoring; replacing turbine meters in alcohol/spirits manufacturing; flow measurement of saturated steam in a continuous process (power/chemical sector); natural gas measurement; and maintenance-free operation of raw water wells.

For details contact: Metrohm India Ltd 205/206, Sector III Bldg 5 Millenium Business Park Mahape, Navi Mumbai 400 710 Tel: 022-27781003, 27781026, 27781027 Fax: 91-022-27781028 E-mail: joy@metrohm.in

Electro Magnetic Meter The instrument works on the principle of Faraday’s law of Electromagnetic Induction. A magnetic field is generated by the instrument in the flow tube. The fluid flowing through this magnetic field generates a voltage that is proportional to the flow velocity. This voltage is measured by the electronics and a corresponding output provided. Universal power supply accepts any voltage from 90 to 265 V AC. Bi-directional flow measurement measures the flow in both forward and reverse directions. Built-in totaliser provides a separate totalized volume value for flow in each direction. Remote monitoring is easy monitoring of the process even in hard to reach places. Conforms to International Standards - designed to meet global requirements and available with international approvals. For details contact: Toshniwal Hyvac Pvt Ltd 267 Kilpauk Garden Road, Chennai 600 010 Tel: 044-26448558, 26448983, Fax: 91-044-26441820 E-mail: sales@toshniwal.net www.oswindia.com

For details contact: Toshniwal Hyvac Pvt Ltd 267 Kilpauk Garden Road Chennai 600 010 Tel: 044-26448558, 26448983 Fax: 91-044-26441820 E-mail: sales@toshniwal.net

Continuously Regenerated Trap Column Designed for eluent generators in RFIC s y s t e m s , t h e D i o n e x C R -TC c o n t i n u o u s l y re g e n e r a t e d t r a p c o l u m n s re m o v e a l l anionic or cationic contaminants in t h e e l u e n t c o n t i n u o u s l y a n d p ro v i d e ver y low baseline drift during gradient operations. For details contact: Thermo Fisher Scientific India Pvt Ltd 102, 104, Delphi ‘C’ Wing Hiranandani Business Park Powai Mumbai 400 076 Tel: 022-67429494 Fax: 91-022-67429495 E-mail: sagar.chavan@thermofisher.com

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EVENTS DIARY

events diary Shanghai International Petrochemical and Offshore Oil & Gas and Chemical Industry Technology & Equipment Exhibition

Date: 23-25 August 2018 Venue: Shanghai New International Expo Centre, Shanghai, China Event: Petrochemical, Oil & Gas, Chemical Industry Technology and Equipment Exhibition is a 3 day event being held from 23 to 25 August, 2018 at Shanghai New International Expo Centre (SNIEC) in Shanghai, China. This event showcases products and technology of Petrochemical, Oil & Gas, Chemical Industries. Exhibition area covers: automatic instruments and meters, Fire safety protection and emergency management technology, pipeline storage and transportation, oil field inspection, UAVs, Oil field chemicals, valve and pump, new materials, petroleum upstream equipment, machinery manufacturing equipment, solid waste treatment zone, exhibits including waste disposal and recycling, hazardous waste disposal, soil remediation, sludge treatment/material dehydration, oilfield sewage/wastewater treatment equipment, fastener and fluid machinery manufactures, etc. For details contact: Beijing Zhenwei Exhibition Co Ltd 801, Bldg E, Kaixuancheng, 170, Beiyuan Road, Chaoyang District, Beijing, China

4 th Annual IoT in Oil & Gas Conference

Date: 18-19 September 2018 Venue: Hilton Americas-Houston, USA Event: The IoT in Oil & Gas 2018 Conference will focus on helping operators drive down costs and increase efficiencies. Over the past 3 years, thousands of oil and gas IT and OT leaders have met with the world’s leading solution providers to discuss how IoT technology can assist them in sur viving and thriving in the sustained low oil price environment. The 2018 program will see an evolution of topics, with more case studies as the technology becomes more embedded in the industr y. For details contact: MacKenzie Blankenship Tel: 855-869-4260 Email: mackenzie.blankenship@energyconferencenetwork.com

Offshore Safe Lifting Conference & Expo

Date: 19-20 September 2018 Venue: Norris Conference Centers - Houston/City Centre, Houston, U.S.A. Event: Exploring the opportunities in oil and natural gas industry. The Offshore Safe Lifting Conference & Expo, organized by the American Petroleum Institute (API) will take place from 19 to 20 September 2018 at the Westin Houston Memorial City in Houston, U.S.A. The conference will cover latest in offshore developments while sharing experiences, practices, and even information on real-life incidents. For details contact: The American Petroleum Institute 1220 L Street, NW Washington DC 20005-4070, U.S.A.

Sakhalin Oil and Gas Conference & Exhibition

Date: 25-27 September 2018 Venue: Stolitsa Business Centre, Yuzhno-Sakhalinsk, Russia Event: The Sakhalin Oil and Gas Conference & Exhibition features exclusive project updates from the region which cannot be heard from anywhere else along with a high-level strategic discussion between top government officials, NOCs and IOCs. It is a must-attend event for anyone interested in the oil and gas industry of the Russian Far East. For details contact: Adam Smith Conferences Maple House, 149 Tottenham Court Road, W1T7AD, London, U.K.

Annual Cybersecurity Conference for the Oil & Natural Gas Industry

Date: 6-7 November 2018 Venue: The Woodlands Waterway Marriott Hotel & Convention Center, The Woodlands, U.S.A. Event: The Annual Cybersecurity Conference for the Oil & Natural Gas Industry, organized by The American Petroleum Institute will take place from 6 to 7 November 2018 at The Woodlands Waterway Marriott Hotel & Convention Center in The Woodlands, U.S.A. This conference provides the attendees with an opportunity to discover methods for thwarting the bad guys, what the scene looks like over the horizon and how the latest technologies can help to counter cyber espionage, address cyber warfare, and make the cyber efforts secure. The conference aims to provide an opportunity to network with cybersecurity professionals, and to candidly discuss challenges and share solutions. For details contact: The American Petroleum Institute 1220 L Street NW Washington DC 20005-4070, U.S.A.

ADIPEC 2018

Date: 12 - 15 November 2018 Venue: Central Plaza, Al Maa’red Hall, Abu Dhabi Event: Established in 1984, the Abu Dhabi International Petroleum Exhibition and Conference is a world-class business forum, where oil and gas professionals convene to engage in dialogue, create par tnerships, do business and identify solutions and strategies that will shape the industr y for the years ahead. ADIPEC has grown exponentially to become the world’s meeting point for oil and gas professionals. Today, over USD 10.34 billion of business is concluded during the exhibition, placing ADIPEC at the ver y hear t of international business of the global energy sector. Over 102,000 trade professionals attend ADIPEC, while 950+ industr y leading exper ts share their knowledge and understanding across the event’s expansive line -up of strategic and technical conference sessions. For details contact: Tel: +97124444909 Email: Adipec.sales@dmgeventsme.com

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BOOKSHELF

The Hitchhiker’s Guide to the Upstream Oil & Gas Industry

Author: Bernhard W Seubert Price: $24.00 No of pages: 190 pages (Paperback) Publisher: Independently published About the book: This book has been written for laymen, for all those who would like to understand the business of oil and gas without having to read through the ballast of technical background. This book is easy to read and nearly free of technical jargon and mathematical formulas. To help with understanding, a glossary has been added as an appendix. The book is meant as an introduction to the large field of geology and upstream petroleum technology. It addresses investment people, students, non-technical managers in an oil company, journalists and all those who want to obtain a quick immersion into the oil and gas industry. If you are in the oil and gas business and need to explain to someone outside the field – this is intended for you. If you are a non-technical person in an oil company or are considering studying geology or petroleum engineering, this is the fastest way to read up on the subject matter. For the seasoned professional who is familiar with the subject matter, this book may come in useful to explain aspects of the business to outsiders. A special effort has been made to point out the stochastic nature of exploration, the value of information and knowledge and the economic and historic back-drop on which all commercial oil and gas operations take place. This book does not claim to be complete and correct to the last detail. Indeed, some aspects have been drastically oversimplified to make them easier to understand. For further study and for those who want to know more, there is a large body of books, teaching videos and webinars on the Internet in additions to commercial libraries. In fact, every aspect of the oil business is so rich in detail and profound in science that it requires study and specialists’ knowledge. The subject of every chapter could be a full career or profession.

Introduction To Petroleum Exploration And Engineering Author: Andrew Clennel Palmer Price: Paperback $38.00 No of pages: 154 pages (Paperback) Publisher: WSPC About the book: This book is an introduction to oil and gas designed to be both accessible to absolute beginners who know nothing about the subject, and at the same time interesting to people who work in one area (such as drilling or seismic exploration) and would like to know about other areas (such as production offshore, or how oil and gas were formed, or what can go wrong). It begins by discussing oil and gas in the broader context of human society, and goes on to examine what they consist of, how and where they were formed, how we find them, how we drill for them and how we measure them. It describes production onshore and offshore, and examines in detail some instructive mishaps, including some that are well known, such as Deepwater Horizon and Piper Alpha, and other lesser known incidents. It looks at recent developments, such as shale oil, and concludes with some speculation about the future. It includes many references for readers who would like to read further. Mathematical content is minimal.

Production Chemicals for the Oil and Gas Industry Author: Malcolm A Kelland Price: $120.73 No of pages: 454 pages (Hardcover) Publisher: CRC Press (2nd Edition) About the book: Production chemistry issues result from changes in well stream fluids, both liquid and gaseous, during processing. Since crude oil production is characterized by variable production rates and unpredictable changes to the nature of the produced fluids, it is essential for production chemists to have a range of chemical additives available for rectifying issues that would not otherwise be fully resolved. Modern production methods, the need to upgrade crude oils of variable quality, and environmental constraints demand chemical solutions. Thus, oilfield production chemicals are necessary to overcome or minimize the effects of the production chemistry problems. This book discusses a wide variety of production chemicals used by the oil and gas industry for down-hole and topside applications both onshore and offshore. Incorporating the large amount of research and applications, this new edition reviews all past and present classes of production chemicals, providing numerous difficult-to-obtain references, especially SPE papers and patents. Unlike other texts that focus on how products perform in the field, this book focuses on the specific structures of chemicals that are known to deliver the required or desired performance - information that is very useful for research and development. Each updated chapter begins by introducing a problem, such as scale or corrosion, for which there is a production chemical. The author then briefly discusses all chemical and nonchemical methods to treat the problem and provides in-depth descriptions of the structural classes of relevant production chemicals. He also mentions, when available, the environmental properties of chemicals and whether the chemical or technique has been successfully used in the field. This Edition includes two new chapters and nearly 50 per cent more references.

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