OSW Feb March 2013

OFFSHORE WORLD VOL. 10 NO. 2 FEBRUARY - MARCH 2013 Mumbai ` 150

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contents FEATURES VOL. 10 NO. 2 FEBRUARY – MARCH 2013 MUMBAI ` 150

HSE Management of ONGC’s Mega MHN Project – Success Story by L&T - Mohammed Shadab and Rohidas Chaskar

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Skin Effect Heating Systems for Kharyaga Field - Heinrich Fluch

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Solar-Powered Diaphragm Pumps Enhance Shale Gas Profitability - Tom O’Donnell and Ravi Prasad

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

Jasu Shah Maulik Jasubhai Shah Hemant Shetty

EDITORIAL Editor Sub-Editor Copy Editors Editorial Advisory Board Design Team Events Management Team Subscription Team Production Team

Mittravinda Ranjan (mittra_ranjan@jasubhai.com) Sneha Sinha (sneha_sinha@jasubhai.com) Rakesh Roy, Mahesh Kallayil D P Mishra, H K Krishnamurthy, N G Ashar, Prof M C Dwivedi Mansi Chikani, Rakesh Sutar Abhay Dalvi, Abhijeet Mirashi Dilip Parab, Girish Kamble V Raj Misquitta (Head), Arun Madye

Taking Credit for Emergency Shutdown Devices in Relief System Sizing and Design 11 - Ram K Goyal Blowout Prevention 14 - Jason Knights

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The Case for Interlocking Pig Launchers and Receivers on Offshore Platforms 16 - Lakshmanan Venkateswaran Strive for LIFE Campaign – Focus on Class-1 Risk 18 - Dr Zafar Khan

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How to Stay Healthy Offshore 20 - Joerg Fitzek Robust HSE Practices in LNG Value Chain is the Key to its Stellar Performance 22 - Dr M R Srinivasan Different Energy Commodities on Different Path 25 - Niteen M Jain and Nazir Moulvi Safety from the Ground Up 26 - Dave Stout EMEAI Are You Safe Enough? 28 - Amit K Aglave

NEWS FEATURES Cabinet Nod to Form SPV for TAPI Pipeline Project Speeds Up 30

TRENDS News 31

MARKET INSIGHTS Products 55

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

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features Case Study

HSE Management of ONGC’s Mega MHN Project – Success Story by L&T This paper highlights the Health, Safety and Environment (HSE) Management System and its implementation during execution of MHN Process Platform and Living quarter Project, a project executed by L&T on EPIC basis for ONGC in Mumbai High North (MHN) field. All the critical, non routine and high risk activities were carried out safely during various phases of project along with the Hazard Identification and Risk Assessment (HIRA) techniques, robust implementation of Permit to Work System and Job Safety Analysis (JSA).

In the project, HSE surveillance was given strong emphasis and was supported by regular inspections and checklist criteria by Line Managers and Safety Engineers.

Successful completion of the project with 17 million safe Man-Hours across the different phases of the project was a great achievement. The capturing and assessment of unsafe act and unsafe conditions were set right on top priority which assisted in creating a safe work environment and improve morale of each one of us working for entire project.

Project scope involved Sur veys, Engineering, Procurement, Fabrication, Transportation, Installation, Hookup and Commissioning of all facilities which included a large offshore Process Platform, a separate 150 men Living Quarter Platform and two flare platforms, all connected by bridges. The new platforms were also to be bridge connected with existing MNW Platform constructed by EIL and L&T under a separate project in 2004. Over 80,000 MT of structures, process facilities and utilities were to be fabricated in L&Ts facilities at Oman and Hazira and later installed and erected at Mumbai High offshore. The new facilities along with the existing facilities of NA, BHF and MNW are known as MHN process complex.

The following HSE practices and controls aided/contributed in safe and successful completion of the MHN Project: SAFETY INCENTIVE SCHEME A daily safety incentive scheme was conceptualised and implemented in juxtaposition with monthly safety incentive. This daily incentive scheme was very well received by everyone and proved triumphant in motivating everyone to progressively report the hazards involved in the job at site on daily basis. This not only assisted in capturing and recording significant numbers of local hazards presents at site but also aided in instantly brinmging down the risks of work environment to As Low As Reasonable Practicable (ALARP) level.

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incentive scheme with prior consultation and communication with entire workforce reinforced positive behavior towards HSE amongst all workmen and was well accepted, responded and participated.

SAFETY FIELD AUDIT (SFA) One of the major HSE milestones for MHN project was the Safety Field Audit of worksite (developed by Industry leader Du-Pont with L&T) in which front line managers visited worksite on regular basis exclusively for conducting SFA. Every Manager, Supervisor and Foreman has contributed in the Safety Field audit of worksite and inspected workplace for HSE compliance vis-à-vis L&T’s own HSE Management System. All the observations arising out of SFA were given high priority and every concerned supervisor/individual has acted proactively to close all the Non-conformities in the given time frame. This also facilitated in creating a safe work environment at the site.

SAFE MANPOWER TRANSFER One of the key challenges during the MHN project was the safe transfer of manpower from Barge to Vessel to Platform and vice versa since many times, hook up barges were not connected by gangway to MNP and MLQ Platforms due to operational constraints during offshore works. This risk was brought down to ALARP level by deputing additional HSE Engineers / Officers to ensure manpower is transferred safely through enhanced supervision, clear co-ordination with all involved parties (viz. Barge, crew boat, platform) and systematic transfer with strict vigil was key to transfer manpower safely.

HSE TRAINING – INDUCTION, BRIEFING, AWARENESS SESSIONS Realising the fact that HSE induction, being the best tool to inculcate Company’s HSE expectations to all personnel involved in the project was given paramount importance during different phases of the projects.

Our HSE Team ensured that all personnel including visitors, vendors, are imparted HSE induction which besides Company’s HSE expectation included various HSE information

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like emergency procedures, brief on workplace hazards and risks, incident reporting procedures, HSE communication and workplace introduction including assembly points, escape routes, location of fire fighting and life saving equipment.

HSE induction for all personnel was ensured before mobilisation at base location, including mass safety briefing at sub-contractor facility, and immediately after reaching offshore site location. Beside the mandatory HSE Induction, a number of Safety Briefings and HSE awareness sessions were also conducted from time to time, both at fabrication yards and at offshore. All Hazard findings and near miss incidents lesson sharing were discussed in Safety Briefings sessions with concerned personnel.

PERMIT TO WORK (PTW) SYSTEM A major emphasis was given to ensure that all critical and non routine operations were duly complied with PTW system. Considering the quantum and magnitude of such mega project with various high hazard activities like working at height, lifting/shifting and handling of huge loads (read Jacket weighing up to 13500 MT), hydrostatic pressure testing, radiography, loadout of jackets and top sides, pre-commissioning/commissioning activities just to name a few.

JSA and HIRA were ensured as a pre requisite to PTW for every critical and non routine activity. Considering the critical nature of offshore activities, even routine jobs, along with critical and non routine jobs, were ensured to be started only after complying with PTW requirements.

Strict adherence to PTW System during the entire project is evident from the fact that no NCs were issued with respect to PTW System.

HSE INSPECTIONS One of the major breakthroughs during the project was HSE Inspections with active participation by line management. Inspection schedule was chalked out and ensured that all HSE inspections are conducted as per the envisaged schedule along with line management to ensure a safe working condition at all times.

The HSE Inspections were not limited only to the site but periodic health and hygiene inspection were also undertaken during the entire phase of the project like hygiene inspection of barge, its galley, yard canteen, etcetera. This scheduled inspection along with line management and other concerned parties (e.g. catering crew, marine spread agencies) not only assisted in findings of deficiencies in the activity/system but it also helped line management in getting acquainted with measures to control the hazards in the work environment. Any deficiencies found during these inspections were rectified on top priority and this has helped to improve morale and efficiency of workforce at site.

SIMULTANEOUS OPERATIONS WITH BARGE OLEG STRASHNOV Heavy lift installation barge Oleg Strashnov had to work simultaneously within anchor pattern of another heavy lift installation barge DB-101 during installation of MNP Platform Topsides. Taking in account the risk involved with simultaneous operations of mammoth barges of such size, SIMOPS were planned for series of activities and a safe and successful SIMPOS was achieved by establishing

dedicated communication channels with all concerned parties, defined roles and responsibilities of all concerned personnel and deciding precedence of activity well in advance to refrain from last minute chaos. Similar system was also followed during hook up phase when installation barge Oleg Strashnov and other hookup barges such as East wind 365, Sea Stallion and Sea Jaguar had to co-exist and work in parallel on installation and hookup activities.

MONSOON WORK Considering the continuation of job during monsoon period, a separate emergency response plan was prepared for ongoing operations. Additional life saving appliances (LSA) along with contingency was made available, other than handover LSA items, for personnel working on platform. All critical activities during this time was planned considering consequences of rain water egress and a separate JSA was ensured for all activities during monsoon period.

HSE PROGRAM Apart from aforementioned HSE Practices, other HSE Programs also were the integral part of HSE Management System. Few of such programs are listed below: • Daily tool box talks • Safety Committee Meetings • Pre-mobilisation safety audit of work cum accommodation barges • Periodical and frequent mock drills • Maintaining daily HSE logbook • HSE evaluation of sub-contractor • Audit of sub-contractor facility/workshop for inspection of offshore tools and tackles.

• Conspicuous display of HSE Posters throughout the site.

• Coordination meeting with Client and Sub-contractor for work activity • Highlighting unsafe acts and unsafe conditions in tool box talks • Incident lesson learning session with all workmen CONCLUSION The greatest challenge was to complete the entire project in best possible safe manner by careful planning throughout the project and splendid adroitness and commitment by all the team members. L&T was able to complete the entire project safely and successfully. Also the HSE initiatives taken by L&T at various stages of project were appreciated by Client. The MNP Process Platform started producing Oil and Gas from 12th October, 2012. This is one step ahead in improving self sufficiency for meeting India’s burgeoning Oil and Gas demand. L&T has demonstrated its HSE Management skills in executing projects of such magnitude and is hopeful that with this HSE benchmark, our splendid record of zero Lost Time Injury in offshore sw operations will continue in coming years.

Mohammed Shadab Assistant Manager – HSE Larsen & Toubro, Hydrocarbon IC, Mumbai E-mail: mohammed_shadab@LNTENC.com Rohidas Chaskar Deputy General Manager – HSE Larsen & Toubro, Hydrocarbon IC, Mumbai E-mail: rohidas_chaskar@LNTENC.com

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features Performance Upgradation

Skin Effect Heating Systems for Kharyaga Field BARTEC delivered skin effect heating systems into the Kharyaga field. The tailor made solution provides engineering, calculation, design, supply, installation, commission, and supervision. The target was to assure frost protection and temperature maintaining at the long transfer pipe lines of the oil field in the oil-rich Nenets tundra.

The Kharyaga field in Western Siberia epitomises the difficulties of Arctic and extreme-cold regions: isolation, extreme weather conditions, and a fragile ecosystem. Yet some years of uninterrupted production have demonstrated the validity of the solutions conceived by TOTAL who invested together with StatOil and the Nenets Oil Company into the Kharyaga oil field near Barents Sea. The Russian government approved this joint venture in 1999. In 2009 BARTEC started to work on Kharyaga phase III development project. The Kharyaga oil field has overall oil reserves estimated to 160 million tons. The field is located in the oil-rich Nenets tundra.

Despite the harsh conditions on the Kharyaga field, located some 60 km north of the Arctic Circle – remote location, winter temperatures down to -46°C and very strong winds – production there has continued uninterrupted since the field came on stream years ago, an achievement owed to a number of specific measures: By drilling with deviated wells from a limited number of pads away from the central processing station the impact of surface installations is minimised. To prevent plugging the waxy oil is maintained at +40°C. All facilities have high-performance insulation and the BARTEC skin effect heating systems are implemented. The first oil line to North Pad was planned and installed for a length of 10,4 km deviated

Direct connection to protective earth for electrical safety

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to the central processing facility. Another line with about 10km followed very fast for an additional pad in the East. The empty caves in the earth are filled with water at +60°C. The workspaces are enclosed and also heated both to protect workers and to reduce the impact of cold on processes. Confined spaces are ventilated to manage explosion risk. During phase III development, waste heat recovery units will be installed on the new gas turbines as an energy efficiency measure.

Kharyaga is located within the permafrost zone in a sensitive environment comprising tundra, swamps, shallow lakes and rivers, with numerous species of flora and fauna. The tundra is an extremely sensitive environment where regeneration takes time. These conditions explain why the field’s development must comply with several environmental principles such as the optimisation of water management; strict limitation of greenhouse gas emissions; prevention of soil contamination and well selective waste collection and disposal. All Kharyaga contractors are required to respect waste management rules; drilling activities are carefully monitored and a ‘No Spill’ policy is applied on the drilling rigs of new pads.

BARTEC delivered its complete skin effect heating systems into the Kharyaga field. The tailor made solution provides engineering, calculation, design, qualified components, installation, commission, and supervision. The target was to assure frost protection and temperature maintaining at the long transfer pipe lines. For this application, the skin effect heating system could show its advantages: It is the most cost effective solution at long or unlimited distance lengths with least number of feeding points. The rugged heating circuit is encapsulated in a heat tube element under the insulation and cladding. There is a constant power output for safe temperatures to protect the medium and installation and the system is certified for use in explosive atmosphere.

The skin effect heating system is an electrical heating circuit using the alternating current phenomenon with a remarkable effect on the inner surface of a ferromagnetic tube. The heating element is a plastic insulated heating cable inside a ferromagnetic steel tube. The heat tube (enclosure) by this use produces the majority of heating power output. At the far end the heating cable is connected to the heat tube end to return the current and close the electrical

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Electrical heating cable splice connection

heating circuit (serial circuit). The current density and flow back is only at the inner surface of the heat tube. This has a thickness of about 3mm. For electrical safety the heat tube (envelope) is connected to ground every 600m. All parts (the envelope) are protected against direct contact by connection to protective earth measure. Even if there is used maximum rated voltage up to 5000 Volts the current flow is always and only at the inner side of the carbon steel heat tubes.

The electrical heating circuit is tailor made designed to any needs by variation of the heat tube size, electrical heating cable size, supplied voltage and insulation material. The high voltage transformer and the distribution panel are customised to the project requirements to meet the operation voltage and load requirements.

The heating cable maximum length in production is 600m. Therefore along the carrier pipeline there are auxiliary devices. These pull & splice boxes are only used at this stage of construction to splice the ends of the heating cables.

The system features allow a maximum heating circuit length of 10km with only one feeding point. The power supply cable is the interconnection between distribution panel and power feeding box and laying in a cable carrier. The power feeding box at the input of the heating system is equipped with suitable high voltage insulator terminals to carry the large current into the heating circuit.

The central feeding point is planned with electrical equipment to activate (energise) the heating circuit and to recognise operation exceeding the allowed limits.

Ammeters are mandatory in the distribution panel to find malfunctions and to monitor the operation current. These necessary measurement values are suitable to see and thermal overload that endanger the heating cable and the plant. The calculation and layout is based on heating cable features in order to match with the necessary power output. Object is to maintain the temperature of the medium inside the pipe work.

The operation current is the driver for the heating power output and also for the maximum surface temperature. The resulting temperature class of this plant specific calculation and layout must be guaranteed. Temperature limiters are installed for safe operation. Therefore the latest BARTEC technology is tested according to the stabilised design method.

The skin effect heating system is an electrical heating circuit using the alternating current phenomenon with a remarkable effect on the inner surface of a ferromagnetic tube.

The assembly and installation for the heating circuit components were done in several stages. The coordination was mainly between mounting of the carrier pipe work and finalising insulation and cladding. There was a strict check sequence sw to follow.

Heinrich Fluch Product Specialist Heating Technology BARTEC GmbH E-mail: heinrich.fluch@bartec.de

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features Optimising Productivity

Solar-Powered Diaphragm Pumps Enhance Shale Gas Profitability India, the fourth-largest energy consumer in the world behind the United States, China and Japan, faces significant energy challenges that have forced it to examine alternate ways to meet its increasing energy demands. One method that continues to increase in popularity worldwide is the extraction of natural gas trapped witjhin shale formations below the Earth’s surface. The article talks about the new diaphragm pump technology which provides enhanced chemical injection solutions designed to optimise shale well production.

India has identified six basins that hold shale gas potential viz Cambay (Gujarat); Assam-Arakan (Northeast); Gondawana (Central India); KG onshore (Andhra Pradesh); Cavery onshore and Indo Gangatic. The Oil Ministry of India sees dependence on foreign oil decreasing by 50 per cent in 2020 and 75 per cent by 2025, due in part to its plans to explore and exploit untapped reserves. India currently imports as much as 79 per cent of its oil.

While it has been known for many years that natural shale gas and oil reserves were trapped in deposits of shale formed from ancient sea basins millions of years ago, technology wasn’t available to economically extract those resources until recently. Various technologies play a prominent role in efficient shale-gas extraction, including the pumps that must be used to inject chemicals into shale wells during the production process known as hydraulic fracturing, or fracking.

BENEFITS OF CHEMICAL INJECTION IN SHALE GAS PRODUCTION Unlocking shale formations through horizontal drilling and hydraulic fracturing initiates the gas recovery process from producing zones deep beneath the surface;

Neptune Solar D™ chemical injection pump that provides accurate injection rates at well pressures up to 1,200 psi.

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a process that often results in more than 20-years of production from a single well.

During the production years, gas operators face additional significant challenges to provide low cost energy to the world’s population. Water and sand entering the well bore, corrosion of steel piping and harsh environmental conditions constantly work against the efforts of those striving to reclaim natural gas.

A resourceful industry soon discovered introducing specific chemicals into the contained well bore counteracted many of the detrimental effects of this harsh environment. Anti-corrosion inhibitors enhance the life of the steel tubing used to conduct the gas stream from the underground reservoir to the surface. Surfactants break the surface tension of water that enters the well bore, effectively reducing the water column pressure on the gas moving toward the surface. With reduced downward pressure exerting by the water column, more gas is extracted from the formation. In cold weather environments, methanol is often used to lower the freezing point of liquid moving through surface transportation piping.

Introducing production-enhancing chemicals into the well is most commonly accomplished with a pump at the surface. The pump’s primary purpose is to consistently and accurately inject a user-selectable type and volume of chemicals into the well, without discharging harmful gases into the environment. Many may argue that the large number of variables in a well disqualify the need for injected chemical volumes to be consistent. However, astute operators know a consistent, repeatable volume of chemical injected into the well enables a predictable outcome – including the monthly usage, and thus cost, of the chemicals injected, the corrosion rate of down-hole steel tubing and, in some cases, even the volume of gas produced.

Equipment reliability and remote monitoring capabilities are additional key requirements of chemical injection pumps located at remote gas well locations.

Pumps requiring frequent maintenance create unpredictable down-hole outcomes resulting from a reduction in injected chemical volume. Additional costs are incurred as skilled technicians are deployed to diagnose and resolve the pump problems.

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Neptune Solar D™ chemical injection pump installed at a well-head site.

Remote monitoring serves as “eyes on the ground” for busy gas well operators.

Traditional once -per- day pump knowledge is augmented by the pump controller’s ability to automatically contact the operator when an anomaly occurs.

Gas well operators benefit on many levels by reducing the time between actual problem occurrence and problem detection at remote well sites.

A NEED FOR A BETTER PUMP To function at maximum efficiency, a chemical-injection system must employ a pump that consistently injects an accurate, user-selectable chemical volume into the well bore. Much of the pump technology currently utilised for this application falls short of that objective. Root causes include inconsistent injection rates, seal failures, chemical leakage, gaseous discharge to the environment and increased maintenance requirements.

At present, the two most prevalent pump styles used to inject chemicals into a well bore are gas-powered (pneumatic) and solar-powered reciprocating piston pumps. Despite the widespread usage, these pump technologies are prone to recurring issues that may cause significant problems for natural gas producing companies.

Although low-cost, comparatively simple to operate gas-powered pumps are popular among natural gas producers, they are now being phased out due to a heightened focus by governmental regulating entities on the potential harmful effects of greenhouse gases. As a part of the pump’s normal cycle, gas-powered pumps vent natural gas (methane) and other compounds (such as carbon dioxide and hydrogen sulfide) into the air. A typical gas-powered pump emits from 250 to 650 standard cubic feet per day (SCFD) of dry gas into the atmosphere. Some

of the escaping gaseous compounds are potentially harmful to the environment and can be dangerous to personnel working around the well site.

Gas-powered pumps often experience uneven performance in their principal function – to consistently deliver an accurate, user-selected volume of chemical into the well bore. Gas-powered pumps are powered by the well’s pressure, which can vary significantly. Regulators are used to provide a constant pressure to these pumps, thus adding another piece of equipment that must be maintained, properly set and function correctly to ensure desired pump performance. Any variation in the pressure supplied to the pump can result in a variance in the amount of chemical injected into the well bore. Frequently, gas well operators are compelled to dispatch service personnel to remote well locations to check and adjust dosing rates.

As gas-powered pumps are phased out for this application, many natural gas producers have begun using solar-powered reciprocating piston pumps that feature a timer to control pump cycles. Reciprocating piston pumps typically utilise an eccentric cam connected to the motor shaft to convert the motor’s rotational motion to the axial motion required by the piston. The faster the motor cycles (i.e. revolutions per minute), the faster mechanical connection points between the eccentric cam and reciprocating rod wear and require replacement. However, these pumps contain dynamic seals, which tend to degrade over time. Dynamic seals form a barrier between a moving part (such as a piston or reciprocating rod) and a stationary part (such as the pump housing). As these seals wear, liquid chemical intended for the contained well bore may leak into the environment.

V-packing is a type of dynamic seal common on reciprocating piston pumps. Some of these seals are designed to be tightened at regular intervals. If V-packing seals

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are over-tightened, they can grip the reciprocating rod too hard, causing undue stress on the motor and additional drain on the battery. Maintaining optimal pump effectiveness requires gas producers to regularly dispatch ser vice personnel to the well.

T H E D I A P H R AG M P U M P SOLUTION With gas-powered pumps on their way out, and many solar-powered reciprocating piston pumps not living up Neptune Solar D™ chemical injection pump to expectations, natural gas producers are in need of a new and innovative solar chemical injection system that incorporates a different type of pumping technology. Increasingly, they are turning to an innovative solar-powered chemical injection pump that features diaphragm metering technology.

Diaphragm metering pumps are highly durable and resistant to various chemicals.

Featuring few moving parts and no dynamic seals, diaphragm metering pumps are more reliable and easier to maintain than gas-powered and reciprocating piston pumps. The diaphragm completely separates the chemical side from the hydraulic-fluid side. Regardless of the type of chemical to be injected, seal materials do not require changeout. On the hydraulic-fluid side, there are no O-rings in the pressurising piston sleeve, which means less wear on the piston rod.

Diaphragm metering pumps feature all stainless-steel components in contact with the injected chemical (such as the pump head and check valves), and a chemicalresistant PTFE-coated diaphragm. This robust design helps extend the life of the pump, while preventing chemical leaks and reducing the cost of maintenance.

One of the top monthly operational expenses incurred by many shale gas producers is the cost of the chemical that is injected into the well bore. Frequently, chemicalinjection pumps will be set at a higher dosing rate than prescribed for the well.

This common practice is necessary to counteract pump inefficiencies associated with the current technology (gas-powered and reciprocating piston). Diaphragm metering pumps address this concern by consistently injecting user-selected chemical volumes into the well bore with extreme accuracy.

SOLAR D™ SOLAR-POWERED CHEMICAL INJECTION PUMP When speaking specifically about chemical-injection systems that utilise diaphragm metering pumping technology, Neptune™ Chemical Pump Company, North Wales, PA, USA, in collaboration with sister Dover Corporation company Ferguson Beauregard, recently created the Solar D™ Chemical Injection Pump.

Relying on the resources and expertise of one of the most trusted names in the energy and chemical-dosing industries, the Solar D pump solves many of the www.oswindia.com

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problems experienced with other chemical-injection systems, thereby optimising productivity and enhancing profitability.

The Solar D pump is based on proven Neptune diaphragm metering pump technology that has been used in industrial chemical-dosing applications for years.

The diaphragm metering pump features a brushless motor, paired with a digital controller for precise, accurate injection rates. Over the pressure range of 300 to 1,200 psi (21 to 83 bar), tests show that the Solar D pump has a dramatically smaller deviation of injection rate within a 95 per cent confidence interval. The result: the need to inject a greater volume of chemical than that prescribed for the well is greatly reduced – resulting in real savings for operators. At 1,200 psi, other solar chemical-injection pumps can vary their injection rate as much as 2.8 per cent (over 4 gallons a month per well - assuming 5 gallons injected per day).

By comparison, the pump’s injection rate varies only as much as 0.9 per cent (less than 1.5 gallons per month per well). Its reliability means fewer technician trips to the well in conjunction with the additional chemical cost savings for operators.

Solar D diaphragm metering pump injection rates are easily adjustable from 0 to 45 gallons per day (0 to 170 L/day). The pump’s digital controller allows users to cycle the pump for exact amounts of time to ensure highly accurate daily injection rates.

An onboard calculation routine enables users to run a common rate test, record the results of that test and plug the values into the controls, thereby allowing the pump to be calibrated to the specific well conditions. The operator is than able to key in the prescribed chemical volume and the controller automatically sets the required cycle times. The pump can also be easily configured to allow remote monitoring via cell phone or interface with existing SCADA systems.

In summary, the Solar D chemical injection system offers numerous benefits previously unavailable to shale gas producers.

• Environmentally friendly, emitting no atmospheric gases • Utilises a seal-less, low-maintenance, diaphragm metering pump technology • Consistently injects accurate user-selectable chemical volumes, enabling lower chemical consumption and corresponding costs, while enabling predictable down-hole benefits.

When considering all of these features and weighing the ownership costs associated with previous pumping alternatives, the new Solar D™ Solar-Powered Chemical Injection Pump provides an efficient solution for overcoming the harsh realities sw of natural gas production from shale formations.

Tom O’Donnell Product Manager, Neptune Chemical Pump Co E-mail: Tom.ODonnell@neptune1.com Ravi Prasad Director of Sales Pump Solutions Group (PSG) India E-mail: sales.psgindia@psgdover.com

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features Key to Survival

Taking Credit for Emergency Shutdown Devices in Relief System Sizing and Design In relief valves sizing, we do not take cognizance of any immediate actions taken by operators or by mitigating devices. However, in the design of overall flare systems to cope with common mode failures such as loss of power or cooling water, many experts these days support taking credit for emergency shutdown systems to reduce investment.

While there is no objection, in principle, to such credit taking, its application in practice deserves careful scrutiny.

In the sizing of individual relief valves protecting equipment or process or system, it is a common practice not to take cognizance of any immediate operator action or the action of any mitigating devices. However, when it comes to designing an overall refinery flare system to cope with common mode failures (e.g., loss of power, or cooling water supply failure), an increasing number of experts are supporting taking credit for the action of devices such as unit emergency shutdown (ESD) systems, trips (for example, fired heater fuel supply cut-offs), or auto-starts of pumps whose actions reduce the potential load on the overall refinery flare system. Savings can thus be realised in the sizing of flare headers and other ancillary equipment. While there is no objection, in principle, to taking credit for ESDs in the design of relief systems, its application in practice deserves careful scrutiny. There are still many related issues that have not been adequately addressed by the proponents of the credit-taking approach. This paper highlights these concerns and offers practical advice to those facing relief system design decisions.

In a modern refinery, the practice of atmospheric discharge of gaseous hydrocarbons from Pressure Relief Valve (PRV) tail pipes, irrespective of whether on-plot or off-plot, is neither permissible under environmental guidelines nor desirable from a safety standpoint. The common approach, therefore, is to tie all (or most) pressure relief discharges from a unit into a manifold or unit header, which is then routed to a refinery relief header connected to a suitably sized flare system. Two systems are sometimes preferred — a low-pressure system and a high-pressure system.

The key parameters in the design and sizing of such a relief/ flare header or manifold are the flow rate, the driving pressure and the type of material expected to enter the header from the discharge pipes of various relief valves connected to it. This in turn depends upon assumptions made as to the concurrence of relieving from several sources.

If it is assumed the header is required to handle the numerical sum of the rated capacities of all the relief devices in all the units discharging to it, then its calculated design size will truly be of enormous proportions — and require an equally enormous flare stack to match! Clearly, such an approach is wasteful and unjustifiable, especially where it can be demonstrated that an event culminating

in simultaneous relief from all the valves at their respective rated capacities is impossible to occur (except, perhaps, as an extremely elaborate act of sabotage).

A certain degree of realism can be injected into the header design process by assuming that the maximum relief load will be equal to the sum of the actual expected maximum relief flows from those valves which could lift under a given emergency situation. For example, consider utility failure (power, cooling water, instrument air, steam, fuel oil/fuel gas, inert gas, or a combination based upon inter-relationship or common cause) or unit/plant fire. The header size derived will be smaller than that resulting from the total rated relieving-capacity assumption discussed previously. It will, however, be large enough to handle the relief load from all foreseeable emergency situations.

Hence, in sizing a header/flare system, there can really be no serious objection to utilising a conservative time-line analysis approach or a dynamic analysis based on process parameter levels expected under ‘upset’ conditions to calculate the required relief load, provided individual peak relieving rates get adequately addressed in the analysis.

Further economy in the header and flare system size can be realised by assuming that, in practice, several of the relief valves will not be required to lift in an emergency. Pressure in the vessels or equipment protected by them will not rise above the PRV set pressures due to the action of any “automatic instrumentation” installed that tends to pacify the source of pressure build-up. Automatic instrumentation here does not refer to the normally operating control systems and instruments used to operate the refinery [sometimes referred to as the Basic Process Control systems (BPCS) — see CCPS (1993) automation guidelines]. It refers to non-normal instrumentation such as emergency shutdown devices (ESDs), trips, safety interlock systems, auto-lockouts or auto-starts (all termed “ESD” for the purpose of this paper).

Size reduction sought on the basis of ESDs (i.e., taking credit for ESDs in relief and flare system design) — though it appears to have a ‘prima facie’ justification — is nonetheless fraught with controversy and a source of genuine concern, especially

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among operations managements. The key question, therefore, is: should we or should we not take credit for ESDs in the relief/flare system design?

the capacity of another PRV connected to the system if the ESDs fail to act in the assumed manner.

Note that the design of other parts of the relief system — such as PRV sizing, individual discharge piping and the header piping — can be carried out on the basis of the various API recommended practices. Applicable sections of the API RPs are illustrated in Figure 1.

The hydrocarbon processing and the chemical industries are sometimes portrayed in the media as being those causing many major incidents resulting in loss of life and property. Setting aside the validity of such claims, there is no denying that most reputable companies have been acutely aware of their responsibilities in terms of safety of the communities and the environmental issues since well before the onset of recent legislation on clean air and process safety management.

Clearly, the biggest advantage of taking credit for ESDs is minimising the size of the relief system required to handle the PRV discharges from a unit or the entire facility. Reduction in relief load means reduced flare stack diameter and length, reduced header and sub-header sizes, and hence lower investment. In addition to the effect on installation costs, and perhaps of greater significance, is the impact of relief load reduction on the following key parameters associated with the performance and siting of a flare stack: • In-plant thermal radiation at grade • Radiation received at adjacent equipment • Radiation level at refinery fence-line • Combined radiation from more than one flare • Dispersion of combustion products • Dispersion on flame failure • Compliance with environmental regulations • Health impact on immediate area • Health impact on surrounding communities • Quantity of product sent to flare.

OBJECTIONS TO CREDIT TAKING There is no objection in principle, to the concept of taking credit for ESDs or any other shutdown devices/trips in evaluating relief system capacities. It is no different from any other cost versus risk-reduction benefit decisions faced by managements every day. In the highly competitive environment, which currently prevails in the oil business, the potential for savings associated with a smaller flare system cannot be dismissed lightly.

Nonetheless, before lending unequivocal support to the concept, a few concerns need to be aired and resolved. From the standpoint of operations and engineering managements these are considered to be extremely significant — in fact so much so as to disfavor the practice of ESD credit taking. Past incidents on record involving flare systems further add to a plant owner’s anxiety in what is perceived as ‘cutting corners’ in the system design. One example is the Grangemouth (U.K.) Refinery incident. Although not related to flare line sizing, it was, nonetheless, a major incident involving a flare system.

API RP-521 states that the discharge piping system should be designed so that the built-up back pressure caused by the flow through the valve under consideration does not reduce the capacity of any pressure relief valve that may be relieving simultaneously. This statement is extremely clear and specific in terms of its content and guiding intent. It can be argued that ESD credit-taking violates the requirement quoted above in that if a smaller header size is selected it may permit the build-up of back pressure to such a level as to reduce www.oswindia.com

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In the post-OSHA period, the punitive element, invariably associated with the law, has forced a major modification in the outlook of many operations managers.

The first question management wants answered is: “Does this decision conform to existing international standards, codes of practice, or guidelines or best-known/ approved practices?” Or, conversely: “Will we be in violation of, or interpreted to be in violation of any international code?” In the past, the fact that the API has been silent on the subject of ESD credit taking would have been just one factor in the overall decision-making process. Nowadays, this silence will get noticed with added alarm.

Lack of a recognised standard leaves engineers and managers, who permit the design and installation of a relief system taking credit for ESDs, vulnerable to the possibility of unfavorable comment from official investigations of any loss or injury incidents involving relief system sizing. This concern should not be considered a mere speculation. Past experience of management on incidents elsewhere, in which established industry practices were set aside in favor of calculated low-risk options, forces us to a closer scrutiny of this issue.

COMPROMISING A KEY SAFETY FEATURE: Even if the law permits taking credit for ESDs, a carte blanche approval can not be granted for this practice. Each application must be thoroughly analysed on the basis of its particular situation.

It can be argued that the ESD credit-taking practice compromises the safety margins.

An “undersized” flare header receiving load from several units makes it possible for an equipment over-pressure event (which might lead to an explosion or fire) to occur simultaneously in more than one or all the units connected to the single flare system following a common mode initiating event such as power failure or cooling water failure.

Correct actuation of an ESD does not necessarily mean the relief load gets reduced to zero at the same instant. Residual heat in the fluid contained in a tower will often be sufficient to maintain flow through the relief valve for some time. Also, the time taken to discharge the vapor inventory from the PRV opening pressure down to the reseat pressure is not negligible.

If you feel extremely confident that the ESD will work and will not permit an overpressure situation to arise, then don’t install a PRV.

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API RP-521, Section 5

To Flare

API RP-520, Part II, Section 5 API RP-521, § 5.4.1.3 API RP-520, Part I, Section 3

API RP-520, Part II, Section 4 API RP-521, § 5.4.1.2

ASME Section VIII, Division 1: UG-125 to UG-136 Figure 1: Applicable standards

If you feel a PRV needs to be installed, then don’t undersize it because you feel the probability of it lifting is low due to ESD action. Provide a full-size PRV. See Kletz (1984).

If you decide to connect the tail-pipe to the flare header, then don’t undersize the flare header because you feel the probability of PRV lifting is low. Provide an adequately-sized flare header.

CONCLUSIONS AND PATH FORWARD While there is no objection to the concept of taking credit for ESDs in the relief and flare header sizing and design, each application needs to be individually scrutinised to ensure plant safety is not compromised. Special attention needs to be given to potential impact on other units sharing the relief header.

reliability targets for high-integrity ESDs or a directive to conduct detailed reliability analyses of such systems.

From an operating company management standpoint, ESD credit-taking is not advisable before this practice is clearly recognised and/or approved in an international standard or code. Lack of such a standard leaves engineers and managers, who permit the design and installation of relief systems taking credit for ESDs, vulnerable to the possibility of adverse comment from official investigations of any loss or injury incidents involving relief system sizing. In a court of law, it would place them in a weak defensive situation.

Even if ESD credit-taking becomes an “approved” practice, operating company management are advised to exercise caution. An extremely risk-aversed interunit spacing in a well laid-out refinery is a valuable asset. It presents a natural barrier to the insurer’s EML calculations. Do not erode this barrier by opting for “savings” in the relief header and flare system costs.

Designers and suppliers of ESD systems need to prove that the on-stream availability and reliability of their systems, so readily demonstrable on paper or in FATs, can be reproduced on-site, and are practically immune to environmental factors arising from geographical location or the work ethos of the client company.

In a market place of ever-shrinking refining margins, the incessant pursuit of cost effectiveness in all decision-making is not merely a desirable activity, but the key to survival. However, cost effectiveness must never be misconstrued to sw mean indiscriminate cost-cutting.

The current API recommended practices (RP-520 and RP-521) appear to be silent on this issue. There are no other internationally recognized standards, codes of practice or guidelines which specifically permit taking credit for ESDs in relief system design.

There is a need to initiate a dialog with the API and/or hold further discussions under the aegis of some other recognised body, such as the NPRA (National Petroleum Refiners Association), for guidelines to be established and placed on record.

Confirmation should be sought from OSHA that taking credit for ESDs in relief system design does not constitute any violation of the intent of OSHA 1910.119 Paragraph (d)(3)(H)(ii) which states that the employer shall document that equipment complies with recognised and generally accepted good engineering practices; the statement being applicable to relief system design and design basis per Paragraph (d)(3)(D) of the OSHA regulation.

In addition to giving approval to the concept, any future internationally recognised standards or codes must incorporate detailed guidelines on the types of ESDs for which credit-taking would be permissible. These should include

Ram K. Goyal Advisor Risk Management Bahrain Petroleum Company, The Kingdom of Bahrain E-mail: Ram_k_goyal@bapco.net

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features Protecting Environment

Blowout Prevention Between April and July 2010, an estimated 4.9 million barrels of crude oil gushed from the damaged Macondo well into the Gulf of Mexico following the explosion that destroyed the Deepwater Horizon drilling rig. This was, according to President Obama, the worst environmental disaster America had ever faced. The response to the Deepwater Horizon disaster has spurred an innovative solution, reports Jason Knights.

By the time the crude oil leak from the Macondo well was stopped, oil had affected more than 1,000 miles of coast in five US states seriously damaging local fishing and tourist industries – as well as the reputation of the offshore oil and gas sector.

Something had to be done to make sure it never happened again.

A new US government department – the Bureau of Safety and Environmental Enforcement (BSEE) – was set up, which has implemented the most aggressive and comprehensive offshore oil and gas regulatory reforms in American history.

But such decisions can also have significant cost implications. According to Duco de Haan, CEO of Lloyd’s Register Energy – Drilling: “The operational cost of drilling a deep water well typically ranges from USD 1 million to USD 1.2 million a day. In some of the ultra-deep water projects, it could take 8-12 days – or even longer – to secure the well, recover and repair the BOP, re-run and then re-test it before resuming operations. So, one incident could cost USD 14 million.”

The annual cost to the industry as a whole of pulling up BOPs runs into many hundreds of millions of dollars.

Spotlight on BOP The disaster was the result of a blowout, and ‘the blowout was the product of human error, engineering mistakes, and management failures’, according to the official report of the US government’s Oil Spill Commission. This put the spotlight on the failure of the well’s blowout preventer (BOP).

A blowout preventer is a large, specialised valve used to seal, control and monitor an oil or gas well. It can be the size of a double-decker bus and, in the case of the Macondo BOP, weigh up to 400 tonnes. It is there to prevent the uncontrolled release of oil or gas and is critical to the safety of the crew, the rig and the environment.

It is the final line of defence.

BOP failures are uncommon, but far from unknown: there have been at least [two] major incidents since the Deepwater Horizon. Failures can be electrical, hydraulic or mechanical. But whatever the cause, failure in such a complex system, controlling 500,000-750,000 pounds of ram force in water that might exceed 9000’ deep, can pose a catastrophic risk of fire, explosion and death.

When a problem is detected in a BOP system or component, a decision has to be made whether to pull the BOP to the surface for inspection – or not. Such decisions are made on the basis of some understanding of what the problem might be, and a risk assessment of the potential seriousness of the fault. www.oswindia.com

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Blowout Preventer

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H o w e v e r, m o s t r i s k assessments currently used in the industry do not employ a uniform process, meaning that ‘pull’ or ‘no pull’ decisions are not being made on a consistent basis.

The human factor is also significant, and can result in decisions that are subjective and non-transparent, which a re d i f f i c u l t f o r s e n i o r management to understand and unacceptable to regulatory bodies.

One of the key recommendations of the O i l S p i l l Co m m i s s i o n’s re p o r t wa s t h at t h e U S should introduce “a ‘riskbased’ regulatory approach” similar to that which “has long-since been adopted in both Nor way and the United Kingdom.”

Blowout Preventer

As a result of the subsequent regulatory changes, there was a clear industry need for a BOP failure-decision model which could detail changes in operational risk quickly and confidently, that removed subjectivity and that was verifiable.

“The software models the performance of the BOP. If everything is working as it should, all on-screen indicators show green. Indicators can move to amber or red depending on the significance of any problem that is detected and entered into the model. Redundancy within BOPs means that they have parallel functions doing the same thing. The risk model can suggest whether a problem in one component or subsystem warrants a decision to pull the BOP, or whether the back-up functions are sufficient to allow the rig to continue operating.”

All ‘pull’ or ‘no pull’ decisions are ultimately made by a human operator. “But,” Alme says, “what the model does is to provide better decision support – consistent factual information – upon which those decisions can be based.”

It also improves audit traceability and regulatory compliance, as decisions can be supported by evidence-based explanations.

“The risk model can and will reduce non-productive time dramatically,” says Duco de Haan “which will save money. But it also gives everyone involved an unbiased assessment of the risk quickly, based upon regulations and specifications, removing the potential influence of cost on the ‘pull’/‘no pull’ decision.”

The model is now in use in the Gulf of Mexico. In a 12-month period, ModuSpec’s Well Control Centre of Excellence in Houston – acting as an independent thirdparty – recommended the continuation of operations on 29 occasions when, following the detection of potential failures, the regulator would otherwise have forced the operator to pull their BOPs to the surface.

And, by preventing non-productive time, this saved operators more than USD 200 sw million in lost revenue – and it helps protect the environment.

Innovative Response Following discussions with leading owners and operators in the sector, Lloyd’s Register group members ModuSpec and Scandpower began work on developing such a model. ModuSpec has extensive experience in the industry, having evaluated 80 per cent of the world’s offshore oil and gas drilling units; while Scandpower’s RiskSpectrum software is used in 50% of the world’s nuclear power plants to help them operate safely.

The BOP Risk Model they created is an innovative new application for the Scandpower software. With the expertise of Lloyd’s Register acquisition WEST Engineering Services, the leading drilling industry BOP specialist, the BOP Risk Model can be taken to the next level.

Scandpower’s Vice President Business Development Inge Alme explains: “There are many similarities between the fail-safe requirements of a BOP and those of the safety systems in a nuclear plant. In order to ensure that they work when they are needed, there is a high degree of functional redundancy built into these systems.

Safety features are duplicated in order to reduce the consequences of single failures.

Jason Knights Global Communications Manager, Energy Lloyd’s Register Group Services Limited E-mail: Jason.Knights@lr.org

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features Risk Mitigation

The Case for Interlocking Pig Launchers and Receivers on Offshore Platforms Pigging operations are inherently dangerous. Opening a pig trap closure while there is pressure in the barrel can shoot the pig out of the launcher at high speeds. Attempting to pass a pig through a partially open outlet valve, or prematurely opening the pig trap in the presence of high levels of toxic H 2S, can have fatal consequences. The article details the case for interlocking pig launchers and receivers on offshore platforms.

The DNV-OS-A101 Standard for Fixed Offshore Installations refers to the use of safety systems, which are designed to prevent, detect, control or mitigate the effects of an accidental event. It states that where hazards are unavoidable, installation design and operation should aim to reduce the likelihood of hazards occurring where practicable by: • simplifying operations, avoiding complex or illogical procedures and interrelationships between systems • mechanical integrity of or protection Mechanical key safety interlocking meets these requirements by providing a logical method of safely controlling pig launching and retrieving procedures, no matter how complex the operation. It ensures that procedures are performed in the correct sequence or not at all. Interlocks will not allow the pig trap door to be opened unless it is depressurised and safe to do so. Human error is effectively taken out of the equation.

Smith Flow Control (SFC) developed a coded-card key interlock system, which meets and exceeds DNV’s Offshore Standards to ensure the total isolation of pig trap vessels. These key interlocks mechanically prove their ‘closed and isolated’ status that enables venting and draining of pig trap vessels before loading or

Diagram of a typical pig trap, using a Smith Flow Control interlock system in yellow.

unloading operations. These principles have been adopted by DNV and are globally recognised international standards.

Key interlocks regulate the entire process by releasing and trapping keys in a predetermined sequence. Operating the unlocked equipment immediately traps the initial (i.e. inser ted) key; when the operation is complete, a secondary (previously trapped) key may then be released thereby locking the equipment in the new position. This secondary key will be coded in common with the next lock (item of equipment) in the sequence. By this simple coded key transfer principle a ‘mechanical logic’ system is created which denies any scope for operator error.

PIG LOADING Interlocks can be customised depending on the application, but in a basic scenario there are a few simple steps to launch a pig safely using interlocks. Each step traps a key and releases a key and keys are only released in order.

Operating a pig trap.

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Keys are used to unlock and open the vent and drain valve respectively. These actions release a key that can then be used to open the vessel door safely and load the pig.

Once the pig is loaded and the vessel door is closed and locked, a key is released to close the drain and vent. This action releases the key that opens the kicker valve and launches the pig.

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Once the pig is launched, the trap is re-isolated by closing and locking the mainline valve. This releases a sequence of keys that depressurises the trap by closing the kicker and opening the vent and drain. The final steps involve closing all valves; the final key is returned to the control room key cabinet where is it kept until the process starts again. No steps can be by-passed in this sequence, nor can steps be taken out of order.

Here is the process in full: System start condition: • All valves are closed and locked closed.

• Vessel door closed and locked closed.

• Key 1 is located in the Control Room Key Cabinet.

1.

A. B. C.

To load pig(s) Insert Key 1 into V1, unlock and open, lock open by releasing Key 2.

Key 2 into V2, unlock and open, lock open by releasing Key 3.

Key 3 into door lock. Unlock and open the vessel door, Key 3 is retained all the time the door is unlocked and/or opened.

*Load Pigs* 2. To isolate, pressurise then launch.

D. Close and lock closed the vessel door, Key 3 is released.

E. Key 3 into V2, unlock and close, lock closed by releasing Key 2.

F. Key 2 into V1, unlock and close, lock closed by releasing Key 1.

G. Key into V3, unlock and open, lock open by releasing Key 4.

H. Key 4 into V4, unlock and open. *Pig(s) Launched* 3. Re-isolate after launch I. Close lock by releasing Key 4.

J. Key 4 into V3, unlock and close, lock closed by releasing Key 1.

A schematic of a typical pig trap, using a Smith Flow Control interlock system.

4. Depressurise trap K. Key 1 into V1, unlock and open, lock open by releasing Key 2.

L. Key 2 into V2, unlock and open, lock open by releasing Key 3.

M. Key 3 into V2, unlock and close, lock closed by releasing Key 2.

N. Key 2 into V1, unlock and close, lock closed by releasing Key 1.

5. Back to ‘dormant/start’ condition O. Key 1 is returned to the Control Room Key Cabinet. *Proposed Sequence Ends* Interlocks do not reduce productivity. The key transfer system is integrated with the operation to create a seamless sequence of events that ensures safety and peace of mind and eliminates the associated risks to people working on offshore platforms.

Valve interlocks are mechanical and do not rely on a power supply. They can be fitted to motorised valves without compromising the valve’s function and failsafe features. As a result, key interlocks provide independent control over the working of manually operated valves, end closures and motorised valves. In practice, this simple concept saves lives and protects plant and personnel during pigging sw operations worldwide.

A typical Smith Flow Control door lock fixed on a pig trap closure. The key (on the right) is inserted into the interlock to release the lock and allow the operator to open the door and load/retrieve the pig safely after all previous steps have been completed.

Lakshmanan Venkateswaran Smith Flow Control Sales Manager for India Halma Trading and Services India Pvt. Ltd. E-mail: V.Lakshmanan@smithflowcontrol.com

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features Hazard Management

Strive for LIFE Campaign – Focus on Class-1 Risk In recent years there has been a realization that the reliability of complex work systems in achieving operational goals safely depends on social structures as well as technical arrangements. A string of high profile disasters over the past two decades has indicated the role that social and organisational issues played in the etiology of these accidents. The article discusses HSE culture, HSE management practices and HSE performance in offshore construction environment.

We have seen even the best HSE conscious companies have failed and have seen major disasters, despite having robust HSE management system in place. While analysing some of the statistics on hazard management, one can easily find following points: • A huge number of hazards reporting; • Close of Hazard is more than 80%; • Good reporting culture.

But are we not losing focus over smaller issue?

This has given further idea to the some of the industry leaders that why don’t we at look iceberg theory of incident causation from two different angles.

Keeping in mind that managing the bottom of the pyramid will help us reduce further incidents but don’t forget the top of the pyramid always has high potential for major disasters. There is no harm adopt this model of risk management of having extra focus on the class-1 hazards (top of the pyramid) while not forgetting the bottom hazards. This strategy has helped many industry safety leaders to avert major incidents and avoid keeping the organisation tangling in smaller issues.

Having said that class-1 risk require more attention due to potential of major incident calls for better control. Such class-1 risk requires some rigid /difficult to fail type of controls. It is therefore ideal to apply hierarchy of control on such risks

and make it mandatory to have at least one or two hard controls to manage such risks. These controls should be supported by further soft controls. The hard controls should be either elimination, substitution or engineering controls supported by administrative and PPE controls.

For example if there is work at height risk and since it’s a class-1 risk the hard control could be – change the methodology avoiding compete risk of work at height or substitute the manpower with machineries or provide some engineering control of proper working platform with proper design and safety nets etc. But this risk control should be supported further by safety trainings, tool box talks, pre-start work briefings, daily safety checks, and supervision type of administrative control and last but not the least personnel protective devices should be mandatory anyway for such risk keeping in mind it is last line of defence.

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The construction industry so far has never been so good applying the hierarchy of control for safety risk, that’s why one has to deliberately put the thought while designing the safety control using this hierarchy of control and start from elimination to PPE not otherwise.

The oil and gas construction industry has always been high risk and day by day due to congested fields (Pipe laying), working on revamping projects as well modifications on live platform has further increased the risk by many folds. Though all the contracting company before going offshore gets ready to undertake the work at offshore during their engineering and procurement phases but very few have been successful applying above described process in their engineering and procurement phase.

Please bear in mind the hard control are largely determined before mobilisation phase of any project that’s why there is larger responsibility on the back office controls to reduce these risk before work gets started in offshore and this calls for a very good proactive culture of safety in each discipline for project management whether its engineering, procurement, logistics of even human resources. Each one has to apply the hierarchy of control while designing the process of all such high risk task where there is an imminent risk of class-1 injury, at least one or two hard controls supported by others soft controls should be applied.

“There’s a difference between interest and commitment. When you’re interested in doing something, you do it only when circumstance permit. When you’re committed to something, you accept no excuses, only results”.

And the class-1 focused risk management strive for LIFE programme as explained above is only possible when everyone in the organisation is committed to sw save lives...

(From the arrow green colour to red colour shows the effectiveness of controls- Green most effective and red least effective)

Dr Zafar Khan Deputy Group Head – HSSE Leighton Welspun Contractors Pvt Ltd E-mail: Zafar.Khan@lwin.co.in

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features Industrial Hygiene

How to Stay Healthy Offshore There has been considerable progress in industrial hygiene issues in offshore environments in recent years. There are many benefits to assessing the risks related to offshore, and developing a well-considered plan of action to manage those risks. The white paper, written in consultation with Dr Jas Singh, Golder Associates’ Hawaii-based health & safety consultant, discusses how one can stay healthy offshore.

Experience in many offshore environments shows that there is growing understanding that Industrial Hygiene (IH) is not as much about emergency plans and response as it is about taking measures to provide for employees’ long term health and wellbeing day to day.

Some of the majors have well-developed IH risk assessments, plans and protocols, and are sharing those with their smaller joint venture partners. Where many companies fall short in their IH obligations offshore is around detailed and systematic assessments of IH risks.

The result may be increased employee injuries, or latent health conditions that may manifest later in the employee’s life through impaired health or quality of life.

Assessing the risks related to IH in the offshore, and developing a well-considered plan of action to manage those risks, has many benefits. These include setting priorities and thus enabling better resource allocation, long-term reduction of illness and injury by identifying health hazards early and better employee morale, resulting in higher productivity and easier recruitment and retention.

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Three aspects unique to offshore environments can make IH issues more consequential than they are onshore: Isolation and Distance. Many managers in the offshore industry underestimate the psychological effects of the offshore environment. Employees are often away from home for weeks at a time.

They may be coping with news about a child not doing well in school, or a family member who is sick, and there is not much they can do about it. This can distract them from their work, in an isolated work environment with many potential hazards.

Small Area, Tight Confines. The small footprint of most drilling platforms results in a crowded environment. Employees are often called upon to physically lift and carry heavy loads, twist and bend – with real potential for ergonomic stress.

Hot, humid environments in warm waters provide welcoming homes for mould to grow, impacting interior air quality. In some situations, exhaust from engines on pumps and other equipment is picked up by ventilation intakes. Even if rooms

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are set aside for smoking, ventilation systems may be inadequate, so smoke drifts throughout the living quarters.

Stressful Environment. In emergencies such as a fire or injury, crew members on remote platforms know that help will take some time to arrive, particularly during storms. The ever-present threat of fire or explosion can weigh heavily on their minds.

The small space available for crew living quarters (bunk beds are the norm) can cause mental stresses that can flare up into interpersonal confrontations and bullying.

RISKS OFFSHORE Routine IH exposures on offshore platforms can come from pigging, routine maintenance and small leaks. Experience shows that most significant exposures may occur during the process upsets and maintenance activities such as vessel cleaning, changing filters, changing gaskets (particularly scraping and sanding broken gaskets), painting and paint removal, and pump maintenance/repair.

One of the best ways to manage these risks is a qualitative risk assessment.

This tool for evaluating and prioritising the risk of exposure to chemical and physical hazards goes beyond routine observation-based occupational exposure assessments to evaluate the inherent hazards of the agents, exposure duration, relative probability of exposure and severity of exposure. It then ranks overall exposure risks.

In IH, risk is considered to be the product of two factors: • The probability of exposure, including the duration of exposure in hours per day, the exposure potential which considers factors such as volatility, particle size and likelihood of physical contact, and the degree of engineering controls present; • Severity or consequence rating, which considers toxicity using well-established methodologies to determine consequences of contact.

Measuring risks, using qualified personnel (either in-house or through a third party) can help find the most serious risks, for setting priorities for action. The result is a safer workplace, which leads to greater employee confidence in their employers’ sw willingness to safeguard their health and safety.

Joerg Fitzek Managing Director R STAHL (P) Ltd Chennai, India E-mail: sales@rstahl.net

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features Ensuring Safety

Robust HSE Practices in LNG Value Chain is the Key to its Stellar Performance LNG has been handled safely for many years and the industry has maintained an enviable safety record. Engineering & design and increasing security measures are constantly improved to ensure the safety and security of LNG facilities and ships. The article details this, and more.

Liquefied Natural Gas (LNG) is natural gas cooled to a temperature of -256°F at atmospheric pressure, when condenses to a liquid. The volume of this liquid takes up about 1/600 th of the volume of natural Gas. It weighs about 45 per cent as much as water and is odorless, colorless, non-corrosive, and non-toxic.

LNG is primarily methane (typically, at least 90 per cent), but may also contain ethane, propane and heavier hydrocarbons and small quantities of nitrogen, oxygen, carbon dioxide, sulfur compounds, and water. LNG supplies come primarily from where large gas discoveries have been made and countries that produce a lot of gas associated with oil fields, such as Algeria, Trinidad, Nigeria, Indonesia, Qatar, Oman, Malaysia, Libya, Abu Dhabi. LNG is used worldwide for fuel electric power facilities.

ADVANTAGES/DISADVANTAGES OF LNG: • Less space, easier to transport and store.

• Can be transported over long distances via double-hulled LNG ships, which are specially designed tankers that keep the LNG chilled during transport.

• LNG is replacing diesel in many heavy-duty trucks and buses and many new gas-fueled locomotives.

• LNG operations are capital intensive. Upfront costs are large for construction of liquefaction facilities, purchasing specially designed LNG ships, and building regasification facilities.

• Methane, a primary component of LNG, is considered a greenhouse gas because it increases carbon levels in the atmosphere when released.

The LNG industry has an excellent safety record. This strong safety record is a result of several factors:

Gas Field

Liquefaction Facility

LNG Storage Tank

1) The industry has technically and operationally evolved to ensure safe and secure operations. Technical and operational advances include everything from the engineering that includes LNG facilities to operational procedures to technical competency of personnel.

2) The physical and chemical properties of LNG are such that risks and hazards are well understood and incorporated into technology and operations.

3) The standards, codes and regulations that apply to the LNG industry further ensure safety. The evolving international standards and codes that regulate the industry.

ACHIEVEMENT OF LNG SAFETY AND SECURITY Safety in the LNG industry is ensured by four elements that provide multiple layers of protection both for the safety of LNG industry workers and the safety of communities that surround LNG facilities.

The four requirements for safety – primary containment, secondary containment, safeguard systems and separation distance – apply across the LNG value chain, from production, liquefaction and shipping, to storage and re-gasification.

Primary Containment: The first and most important safety requirement for the industry is to contain LNG. This is accomplished by employing right materials for storage tanks and other equipment, and by appropriate engineering design throughout the value chain.

Secondary Containment: This second layer of protection ensures that if leaks or spills occur, the LNG can be contained and isolated. For onshore installations dikes

LNG Tanker

LNG Storage Tank

Vaporizers

To Pipeline System

LNG Value Chain

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1) the industry has technically and operationally evolved to ensure safe and secure operations. Technical and operational advances include everything from the engineering that underlies LNG facilities to operational procedures to technical competency of personnel.

2) the physical and chemical properties of LNG are such that risks and hazards are easily defined and incorporated into technology and operations.

3) a broad set of standards, codes and regulations applies to the LNG industry to further ensure safety. These have evolved through industry experience worldwide and affect LNG facilities and operations everywhere. Regulatory compliance provides transparency and accountability.

Single Containment Tanks

and berms surround liquid storage tanks to capture the product in case of a spill. In some installations a reinforced concrete tank surrounds the inner tank that normally holds the LNG. Secondary containment systems are designed to exceed the volume of the storage tank. As will be explained later, double and full containment systems for onshore storage tanks can eliminate the need for dikes and berms.

Safeguard Systems: In the third layer of protection, the aim is to minimise the release of LNG and mitigate the effects of a release. For this level of safety protection, LNG operations use systems such as gas, liquid and fire detection to rapidly identify any breach in containment and remote and automatic shut off systems to minimise leaks and spills in the case of failures. Operational systems (procedures, training and emergency response) also help prevent/mitigate hazards.

Regular maintenance of these systems is vital to ensure their reliability.

Separation Distance: Regulations have always required that LNG facilities be sited at a safe distance from adjacent industrial, communities and other public areas. Also, safety zones are established around LNG ships while underway in waters and while moored. The safe distances or exclusion zones are based on LNG vapor dispersion data, and thermal radiation contours and other considerations as specified in regulations.

INDUSTRY STANDARDS/REGULATORY COMPLIANCE Appropriate operating and maintenance procedures in place ensures that these are adhered to, and that the relevant personnel are appropriately trained. If LNG spills on the ground or on water and the resulting flammable mixture of vapor and air does not encounter an ignition source, it will warm, rise and dissipate into the atmosphere. Because of these properties, the potential hazards associated with LNG include heat from ignited LNG vapors and direct exposure of skin or equipment to a cryogenic (extremely cold) substance. LNG vapor can be an asphyxiant.

In the case of a catastrophic failure, emergency fire detection and protection would be used, and the danger to the public would be reduced or eliminated by the separation distances of the facility design.

Further analysis of data on LNG safety and security is a testimony to its excellent safety record. This is due to:

TYPES OF LNG HAZARDS: Explosion: LNG tanks store the liquid at an extremely low temperature, about -256°F (-160°C), so no pressure is required to maintain its liquid state.

Sophisticated containment systems prevent ignition sources from coming in contact with the liquid. Since LNG is stored at atmospheric pressure – i.e., not pressurised – a crack or puncture of the container will not create an immediate explosion.

Vapor Clouds: As LNG leaves a temperature-controlled container, it begins to warm up, returning the liquid to a gas. Initially, the gas is colder and heavier than the surrounding air. It creates a fog – a vapor cloud – above the released liquid.

As the gas warms up, it mixes with the surrounding air and begins to disperse. The vapor cloud will only ignite if it encounters an ignition source while concentrated within its flammability range. Safety devices and operational procedures are intended to minimise the probability of a release and subsequent vapor cloud having an affect outside the facility boundary.

Freezing Liquid: If LNG is released, direc t human contac t with the cr yogenic liquid will freeze the point of contact. Containment systems surrounding an LNG storage tank, thus, are designed to contain up to 110 per cent of the tank’s contents.Containment systems also separate the tank from other equipment.

Rollover: When LNG supplies of multiple densities are loaded into a tank one at a time, they do not mix at first. Instead, they layer themselves in unstable strata within the tank. After a period of time, these strata may spontaneously rollover to stabilise the liquid in the tank. As the lower LNG layer is heated by normal heat leak, it changes density until it finally becomes lighter than the upper layer.

At that point, a liquid rollover would occur with a sudden vaporisation of LNG that may be too large to be released through the normal tank pressure release valves. At some point, the excess pressure can result in cracks or other structural failures in the tank.

Rapid Phase Transition: When released on water, LNG floats – being less dense than water – and vaporises. If large volumes of LNG are released on water, it may vaporise too quickly causing a rapid phase transition (RPT).7 Water temperature and the presence of substances other than methane also affect the likelihood of an RPT. An RPT can only occur if there is mixing between the LNG and water. RPTs range from small pops to blasts large enough to potentially damage lightweight structures.

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LNG ships and facilities have redundant safety systems, for example, Emergency Shutdown systems (ESD). A redundant safety system shuts down unloading operations when the ship or unloading facility is not performing within the design parameters.

Each onshore LNG container or tank must be within a secondary dike or impoundment area. These thermal radiation exclusion zones must be large enough so that the heat from an LNG fire does not exceed a specified limit for people and property. The thermal radiation exclusion zone must be owned or controlled by the operator of the LNG facility. The code also specifies how the thermal radiation distance is calculated for each LNG facility. The Gas Research Institute (GRI) computer model or a similar model is to be used and wind speed, ambient temperature and relative humidity producing the maximum exclusion distances are to be applied subject to other detailed provision of the regulation.

Similar to the provision for thermal radiation protection, there exists a specification that each LNG container and LNG transfer system must have a flammable vapor dispersion exclusion zone around the facility that is owned or controlled by the facility operator. The vapor dispersion exclusion zone must be large enough to encompass that part of the vapor cloud which could be flammable.

Safety zones differ for ships in transit as opposed to ships in port. Port safety zones are established separately, by specific risk factors at a given terminal. There are two purposes for safety zones for LNG ships– to minimise collision while the ship is underway, and at berth to protect surrounding property and personnel from hazards that could be associated with ignition. The use of safety zones around LNG ships began in 1971 at the Everett Terminal in Boston Harbor. Safety zones are established based on the specific circumstances, including navigational requirements.

The worldwide LNG value chain could not develop without the evolution of international standards that can apply to LNG operations wherever they are located.

LNG TERMINALS DESIGNED TO BE SAFE WITH: Safety features include gas detectors, ultraviolet or infrared (UV/IR) fire detectors, closed-circuit TV, offsite monitoring, personnel training requirements, and restricted access to terminal property.

LNG Lagos - Membrane Type LNG Carrier

have gas- and fire-detection systems, nitrogen purging, double hulls and double containment tanks or leak pans. Should fire occur on the ship, two 100 per cent safety relief valves on each tank are designed to release the ensuing boil off to the atmosphere without over pressurising the tank.

LNG ships use approach velocity meters when berthing to ensure that the prescribed impact velocity for the berth fenders are not exceeded. When moored, automatic mooring line monitoring provides individual line loads to help maintain the security of the mooring arrangement while alongside. When connected to the onshore system, the instrument systems and the shore-ship LNG transfer system acts as one system, allowing emergency shutdowns of the entire system from ship and from shore.

ADDITIONAL SAFETY MEASURES FOR LNG SHIPS To ensure safety for transportation of LNG, the requirement of safety zones around LNG ships is critical. The safety zones prohibit entry by other ships thereby helping to eliminate the possibility of a collision of an LNG ship with another ship.

LNG FACILITIES DESIGNED TO BE SAFE AS FOLLOWS: All facilities that handle LNG have built-in systems to contain LNG and prevent fires. This is true whether in the LNG facility, transferring LNG to and from LNG ships, shipping LNG or vaporizing (re-gasifying) LNG. There are differences in design among these types of facilities, but the environmental, health and safety sw issues are the same.

Fires: Firefighting and other safety equipment is installed at terminals and onboard ships to help manage an incident.

LNG SHIPS DESIGNED TO BE SAFE BY: Designing LNG ships with a double hull to provide optimum protection for the integrity of the cargo in the event of collision or grounding. The ship has safety equipment to facilitate ship handling and cargo system handling. The ship handling safety features include sophisticated radar and positioning systems that enable the crew to monitor the ship’s position, traffic and identified hazards around the ship. A global maritime distress system automatically transmits signals if there is an onboard emergency requiring external assistance. The cargo-system safety features include an extensive instrumentation package that safely shuts down the system if it starts to operate outside of predetermined parameters. Ships also www.oswindia.com

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Dr M R Srinivasan Professor, Department of Petroleum Engineering and Earthscience University of Petroleum and Energy Studies E-mail: mrsrinivasan@ddn.upes.ac.in

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features Energy Review

Different Energy Commodities on Different Path The month of February 2013 saw different price movement for different energy commodities. While NYMEX crude oil futures registered the maximum price fall of 5.58 pe rcent on soft economic data and Italy’s inconclusive election results feeding concerns over Europe’s economy, CER futures prices on ICE-ECX platform rose the most by a significant 107.69 per cent largely helped by compliance buying at extremely low price levels

Light sweet crude oil (WTI) futures on NYMEX (CME) started the month of February at US$ 97.77 per barrel, marginally up by 0.29 per cent from previous month’s close. Though oil prices remained range-bounded especially in the first half of the month, second half of the month witnessed almost steady fall in oil prices. As a result the opening day’s high of USD 98.15 eventually emerged as month’s high.

After the registering of month’s high, news of potential nuclear talks between the US and Iran and rising political tensions in Spain helping a rally in dollar, led to some fall in oil prices. But, oil prices quickly range-bounded as economic data release from the United States and Europe helped improve traders’ view on the outlook for energy demand. While, Europe saw better-than-expected purchasing managers’ index for January, US witnessed manufacturing production and service-sector business activity declining at the slowest rate since last March. Trading of oil prices at high level (largely above USD 95) was further helped as the Organisation of the Petroleum Exporting Countries (OPEC) lifted its 2013 demand forecast. Citing signs of economic recovery and colder weather for the demand increase, OPEC lifted its 2013 oil demand growth forecast to 840,000 barrels a day, an increase of 80,000 barrels a day compared with an earlier estimate.

Thereafter in second half of the month, heavy liquidation (probably) by a commodity fund and talk that Saudi Arabia may boost oil production, led to the considerable fall in oil prices. Weekly report indicating a biggerthan-expected climb in US crude oil inventories and data release from China indicating slowdown in Chinese manufacturing ensured almost steady fall in oil prices. In the later part of the month, Italy’s inconclusive election results feeding concerns over Europe’s economy and energydemand outlook helped the fall in oil prices right till end of the month.

Consequently, NYMEX crude oil futures registered its month low of ` 91.57 on the last trading session of the month, before closing the month at USD 92.05, marking a monthly fall of 5.58 per cent. The fall in crude oil prices was also reflected in the price fall of its derivates such as heating oil and gasoline. Overall, futures prices of both gasoline and heating oil on NYMEX platform saw a monthly fall of 3.68 per cent and 5.05 per cent respectively.

Among other energy commodities, ICE Rotterdam monthly coal futures prices moved up by 5.29 per cent largely on concerns about supply from Colombia, the world’s fourth-biggest exporter. Coal prices responded to news that US coal miner Drummond, which owns Colombia’s second-biggest mine, has had its export licence revoked following reports that a coal barge sank near Santa Marta port in mid-January. Coal prices were also supported as heavy rains in the Australia’s east coast stoked supply worries after two major coal producers declared force majeure on their deliveries. Similar to coal price trend, natural gas futures prices (on NYMEX platform) rose by 4.40 per cent in February 2012, helped by fall in US natural-gas inventories level and the forecasts of continuing cold weather conditions in the US Northeast.

In emission market segment, both European Union allowances (EUA) and certified emission reductions (CER) continued to exhibit price movement largely helped by low price base. Optimism that the European Parliament’s Environment Committee (ENVI) will vote in favour of the back-loading proposal and heavy compliance buying led to big rise in both EUA and CER prices. Overall, On ICEECX platform, while EUA futures prices jumped by 45.02 per cent, CER futures sw rose by a significant 107.69 per cent.

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

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features Safe Working

Safety from the Ground Up In the light of ever-more-dangerous explorations in deep oceans and harsh climates, safety remains an increasinglyimportant issue, not just for the people involved but for the greater environment. While making a mistake might cause an injury, making the same mistake in different circumstances could result in billions of dollars worth of damage, both to a company’s reputation and to the environment. Here Dave Stout from global engineering services and bolting company Hydratight, reveals that safety is more than just what a company does: it has to be built into everything it is.

The world of standards, health and safety changes all the time, but never has it changed faster than in the first few years of the 21 st century.

joints may leak, and the escaping material can be highly toxic, inflammable and under high pressure.

The discovery of new fields off Brazil and in the Caspian Sea; the drive to recover oil from tar sands in Canada and the urgent need to recover every kilowatt of oil energy available is leading producers to take steps to secure production they would not have taken 20 years ago — even if the technologies to make it possible had been available.

Industry technicians simply aren’t held to the same standard of competence as aerospace workers; in fact the same standards aren’t even demanded for welded and bolted joints. In many countries welds must be made by a fully-certified welder; where no such requirement usually exists for bolted joints. Untrained technicians can thus use incorrect bolt loads and gasket materials and make tensioning errors. Failure to properly inspect the result sends the potential for leakage dramatically higher.

But at what cost?

Despite regulation, the Gulf of Mexico suffered the Deepwater Horizon disaster and its massively-expensive clean-up. Governments are increasingly clamping down on private companies in the light of that tragedy, and where governments themselves take the production lead, safety — and protection of the natural environment — are gaining higher priority.

Oil and gas production is a risky business: there is no good reason to increase the risk by gambling with safety procedures and the integrity of production systems.

Whatever can be done to aid safety should, reasonably, be done.

A major problem for companies is compliance: what conformed to code a decade ago might not today. But one way to ensure compliance is simply to do the job diligently, avoiding the mistakes that might lead to problems and expensive corrective work.

Part of the problem is psychological: workers used to varied jobs can become bored after repeating the same process several times: short-cuts creep in, a lack of care becomes evident; mistakes can be made.

Most organisations now recognise this and train technicians to a far higher standard: I liken the work of refinery refurbishment, for example, to that of the aerospace industry. In an aeroplane plane there can be 30,000 hydraulic connections: no one would expect hydraulic fluid to spray even from one of those joints in flight. But in a typical refinery up to five per cent of the 40,000 or more flanged www.oswindia.com

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Jointing specialists have developed systems for “joint integrity assurance”, which follow the jointing process from first-fit to final checks, recording everything along the way. In the new race for safety, these checks at least ensure that once oil and gas are extracted from difficult wells, none of the precious material will be lost in transmission.

Such systems, and others covering many more aspec ts of ever yday operations and maintenance, are gradually taking hold on the industr y, since they often result in far fewer shutdowns. Indeed they may be inevitable: strong regulation is being incorporated into legislation in many countries: companies striving to achieve greater safety now are merely making an early start.

The bottom line is literally the bottom line: a plant that performs safely can save tens of millions of dollars and many lives. Being safe ultimately saves far more than it costs.

But how do we maintain a strong safety record in one of the most dangerous industries in the world?

This is the task facing many oil and gas operators in the 21st-century, and one that must increasingly be addressed by companies large and small following the tragic events in the Gulf of Mexico in 2010 and the vast cost, both to human life and to the environment that resulted from it.

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Though it is impossible to say whether tougher safety measures would have prevented recent disasters, Governments around the world have nonetheless embarked upon major reviews, investigations and discussions to strengthen legislation governing oil and gas industry safety.

Regardless of major disaster or legislation, smaller but still costly and damaging cases of neglect and error occur all too often throughout our industry every week.

It is these “day-to-day” events that can be addressed by developing the correct safety culture throughout an organisation.

Safety should be the goal of everyone within the industry, the company believes, and by extending its accredited, internationally-recognised training courses, Hydratight is helping to create a growing core of well-trained, safe-working technicians, taught by some of the industry’s most experienced engineers operating around the world. Knowledge and expertise are thus passed to colleagues and trainees on day-to-day projects.

In this way the cause of general training and competent, safe working is carried forward to a new generation of industry personnel - all working to a higher, common standard and, in a small way, gradually helping to spread this message across all companies and levels of the industry.

Some companies believe safe working practices can be fostered by offering rules and guidelines reinforced by annual or monthly award schemes, or even financial prizes. However, I believe safe working within the industries in which the company works calls for more than just award or prize systems: the philosophy of safety should be built into the organisations DNA. Any organisations should be concerned that every employee exercises an extraordinary level of care at all times, so to some degree awards are unnecessary.

safety system though publications, meetings, regular briefings and continual reinforcement of the message. It takes only one person to operate dangerously, but many to deal with the consequences.

Management tools to permit the system’s implementation are a necessary evil: risk assessment, competence management, practice controls, records and data management all have a significant role to play.

There is an old fashioned idea that safety isn’t in the rulebook but in the head; that common sense and experience are vital prerequisites for safety to be maintained across company operations. While this is to some extent true, modern working practices simply don’t permit individuals to decide for themselves what might be safe and what might not: the industry is too complex and operations and processes too wide-ranging for any one person to assume full knowledge and understanding in every situation.

If nothing else, accident investigation and correction can operate only on what has happened and was documented — not what was going on in the head of the individuals involved.

Best practice needs to be adopted everywhere, with procedures specific to each operation. There needs to be a plan for proper procedure and inspection, and all the data needed by trained personnel to do their job properly needs to be available on demand, not locked away in someone’s office.

In the best implementations, where training and skills are given a high significance, management also needs a way to know which personnel are able to undertake specific tasks.

Having said that, there is no harm in passing the thanks of clients to those responsible for successful projects and accepting recognition for a good job well done.

I wouldn’t allow a relatively new recruit to work on a high-pressure, hightemperature line that carries lethal chemicals, for example, so managers need to know exactly who is capable of doing what, and what stage of training has been reached by each technician.

Organisations should be seen to educate staff with regular briefings on the ways training and development can affect personal performance and, in turn, overall company performance.

Only when this information is fully recorded and available can a definitive team be put together to carry out any job – or indeed any trainee be assigned to an experienced team so that he or she might learn from their example.

Building safety systems into everyday operations need not be very costly in terms of cold, hard cash, but it does require an organisation to take them seriously, to take “ownership” of safety matters and protect them against the laziness, cost-cutting and negligence that weakens them and lays a company open to greater danger, injury and damaging investigation and litigation.

You might wonder if this takes up a lot of management time, and the answer is sw no. Working safely really does pay off, when you do things right.

It starts with a senior management process that gives a senior individual the responsibility for, or “ownership” of, instituting safety policy matters, and supporting that person’s work.

Next is awareness: everyone with an influence on safety, whether managers or site supervisors or team leaders or individual colleagues, should be aware of the

Dave Stout EMEAI HSSE Manager Hydratight

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features Safer Work Environment

Are You Safe Enough?

Offshore operations is a highly specialized industry. In the past, failure to recognize and eliminate hazards associated within offshore operations has resulted in serious injuries, deaths, costly property damage, downtime and environmental impact. The strict regulatory and environmental requirements have led to additional operational complexities and challenges.

Frequent and continuous advances in technology have also resulted in raising expectations from process automation and safety systems being deployed.

Safe and profitable operations in refineries therefore require effective use of automation technology and outlook in addition to effective implementation of Safety Instrumented Systems.

Process Safety, Why is it important? From the perspective of the operations manager, safety is important for protecting personnel, equipment and the environment while producing safely. Safety is maintained when the risks of serious incidents are mitigated. A question that is constantly in the mind of the operations manager is “Are we safe enough?” In fact a survey of Honeywell customers conducted in 2011 found that safety is the topmost issue on the operation managers’ mind. And this is not an unreasonable finding, when one considers that safety-related incidents can cause injury to personnel, equipment and the environment, as well as interrupt production capability.

Accidents such as Macondo in the Gulf of Mexico that happened in 2010 or Piper Alpha in North Sea in 1988 has tarnished the image of offshore oil and gas exploration and production industry.

According to data published by the U.S. Bureau of Labor Statistics (BLS) in 2010, a total of 120 fatal work injuries occurred in the oil and gas extraction industry in 2008. The three most frequent fatal events in 2008 were transportation incidents (41 percent), contact with objects and equipment (25 percent), and fires and explosions (15 percent).

If data for past 30 years is referred, the 100 largest accidents in chemical and hydrocarbon processing facilities have severely injured or killed hundreds of people, contaminated the environment, and caused more than $8 billion in property damage losses.

The actual cost of these accidents was in fact much higher when taking into account the associated business interruption costs, cleanup costs, legal fees, fines, losses of market share, etc (Source: American Petroleum Institute and the American Chemistry Council). www.oswindia.com

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There are numerous catastrophes that can be cited, but they all indicate the need for focusing on layers of protection to provide a safer work environment, while at the same time increasing process availability and reducing total cost.

BUILD LAYERS OF PROTECTION FOR SAFER FACILITIES The layers-of-protection concept is described in Functional Safety standards such as IEC 61508 and IEC 61511. The layered architecture is a well-designed and implemented process design that is the embodiment of the business, safety, and production considerations necessary for effective operations. The process must be controlled by a secure process control network that extends across the entire plant and business networks. Managing the plant’s assets ensures that the process design continues to function as intended, all while protecting the plant from pending incidents with an early indication of failing assets.

To get started, an operator should first start with the assessment of the site, and aim to identify layers of protection; i.e. Process control, Shutdown systems, Integrated Fire and Gas Systems, and should integrate security solutions with safety solutions. One should also assess how much risk mitigation is achieved by each of these layers, whether each layer can operate or function independent of the other layer, and whether additional layers are required or not.

The layers can either be automated, such as the emergency shutdown (ESD) equipment, or require human interaction such as operator responses to process alarms. Some layers offer easily quantifiable risk-reduction benefits, but require that the risks all be identified in advance. And there are other layers that are less tangible and offer softer benefits.

As one moves through the layers of protection further away from the core of process design, mitigating risk due to human error is the key to ensuring safety.

Implementing tools and procedures (such as boundary and alarm management and early event detection) for the purpose of managing abnormal situations reduces incidents and prevents escalation. Appropriate operating windows need to be defined and managed, and properly designed emergency shutdown systems must be in place as preventative measures in the event that an incident escalates beyond the inner layers of the sphere of protection.

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Working across the various layers of protection, a plant or facility must operate in a secure and protected atmosphere, including protection of the perimeter, facility, people, and assets. With the correct work practices and technology in place, in the event that an abnormal situation does occur disrupting safe operations, an emergency response plan can be executed, controlled and monitored to minimize the impact of the incident.

THE DIFFERENT LAYERS OF THE PROCESS SAFET Y CAN BE BROADLY CLASSIFIED INTO FOUR MAJOR CATEGORIES: • Maintain Stable Control: The capability of the control system to maintain the process conditions within limits, can decide if the stable control and safe operations can be achieved. The alarm and boundary management ensure that the process operator operates the process within the design limit.

• Reduced Unexpected Equipment Failures: The equipment and assets reliability, performance and safety parameters monitoring not only results in reduced downtimes, but also ensures preventive actions to be taken on the faulty equipment, before it results into hazardous operating conditions, which may result into accidents.

• Reduce Human Error: An abnormal situation occurs when the automation system cannot correct a process disturbance. The Abnormal Situation Management (ASM), like general emergency management, is achieved through Prevention, Early Detection, and Mitigation of abnormal situations.

• Improve Automated Emergency Response: The last defense in automated process safety is deployment of the Safety Instrumented Systems. These systems are designed for low probability of failure during demand conditions, i.e. during out of control process. Internationally accepted Functional Safety standards such as IEC61508 and IEC61511 provides guidelines for effective design of the Safety System and its components and take a lifecycle approach for the safety systems.

THE SAFETY SYSTEMS ARE CATEGORIZED BROADLY INTO TWO CATEGORIES: • Preventive Safety Systems (Emergency Shutdown Systems and Bruner Management Systems) • Mitigation Systems (Fire and Gas Systems) The IEC61511 standard recommends that each protection layer should be functionally independent from each other. This ensures that multilayer protection is applied to the critical refining process and only failure of multiple layers would result into an accident.

SUMMARY The process safety for offshore operations not only requires maintaining stable control, but also requires reduction of unexpected failures, human errors in operation and proper implementation and maintenance of Safety Instrumented Systems. Safe and reliable operations of the refining process can be ensured through this layered approach of Automation and Safety. Does your site have sw these independent yet interrelated layers of protection?

Amit K Aglave Senior Manager - Customer Marketing TUV Rheinland Functional Safety ; Honeywell Process Solutions India E-mail: Amit.Aglave@honeywell.com

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news features

Cabinet Nod to Form SPV for TAPI Pipeline Project Speeds Up The Union Cabinet gave its approval for formation of the Special Purpose Vehicle (SPV) for the Turkmenistan-Afghanistan-Pakistan-India (TAPI) Pipeline Project and to permit GAIL India Ltd. to join the SPV. The four countries involved in the TAPI Gas pipeline project, signed an Inter-Governmental Agreement along with a Gas Pipeline Framework Agreement (GPFA).

To accelerate the project, parties have formed the Minister Level Steering Committee and Technical Working Group (TWO). Suitable provisions for security & safety of the pipeline have been made in the Inter-Governmental Agreement (IGA) and Gas Pipeline Framework Agreement (GPFA).

In the meeting of the 16th Steering Committee held on 23rd September, 2012, all parties reaffirmed their commitment and intention to fast track this important regional co-operation project.

As a way forward, Turkmenistan suggested the formation of a SPV by the TAPl members. The SPV would take up the Feasibility Study and Design work of the TAPl pipeline to meet the agreed timelines for the project, as well as search for a consortium lead. Turkmenistan and Pakistan agreed to the formation of TAPl Ltd considering it to be in consonance with the GPFA. Afghanistan also agreed to the formation of TAPl Ltd so long as there was consensus amongst the Parties.

TAPl Ltd is required to have an initial contribution of USD 20 million that is USD 5 million from an identified entity from each of the four participating countries.

GAIL, being a Navratna Company, is empowered to make an investment of this level for India.

GAIL has agreed to make an investment upto USD 5 million in the proposed SPV that is TAPI Ltd. An active interest in the project by all the partner countries at this stage would sustain the credibility of the project, and generate interest in the international market and could eventually pave the way for selection of an appropriate consortium leader in the future.

TAPI Pipeline

The pipeline originates and runs 144 km in Turkmenistan, passes 735 km through Afghanistan and travels 800 km in Pakistan en route India.

The four countries signed the gas sale and purchase agreement last May. The 1,680 km pipeline will carry 90 million cubic metres a day (mmcmd) of gas and is scheduled to become operational in 2018 and supply gas over a 30-year period. India and Pakistan will get 38 mmcmd each, while the remaining 14 mmcmd will be supplied to Afghanistan. TAPI will carry gas from Turkmenistan’s Galkynysh field, known earlier as South Yoiotan Osman that is known to hold gas reserves of 16 trillion cubic feet.

Turkmenistan, which holds more than 4 per cent of the world’s natural gas reserves, signed pacts last May to sell gas last to India and Pakistan through the sw 1,680-km pipeline at the Caspian Sea resort of Avaza in Turkmenistan.

Based on an `in-principle` approval of the Cabinet on 18th May, 2006, India joined the Turkmenistan-Afghanistan-Pakistan (TAP) Project in April, 2008 and thereafter, the name of the project stood amended to Turkmenistan-AfghanistanPakistan-India (TAPl) Gas Pipeline Project. www.oswindia.com

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news

India ONGC Achieves Milestone in Drilling Deepest Water Depth Well Mumbai: State-owned Oil and Natural Gas Corp (ONGC) has achieved a world record for drilling well in the deepest water depth by an offshore drilling rig.

The milestone achieved by ONGC by using a rig, DDKG1, which ONGC had hired from Reliance Industries.

DDKG2 working for Reliance Industries Ltd, in the east coast. The Reliance block where the drilling was done was in Cauvery-Palar offshore basin. Blocks in the Cauvery-Palar region are called ‘wild cat’ blocks in the exploration industry as they are located in new frontier areas.

The rig DDKG1 has spud well NA7-1 in exploratory block KG-DWN-2004/1 in the east coast at a water depth of 3,165 m (10,385 feet). With this Transocean has surpassed its own record of 10,194 feet of water depth, set in 2011 by

After drilling, the drill-ship has successfully lowered and latched sub-sea BOP (blow out preventer) and riser (is the process of connecting the drill pipe with wellhead) on wellhead to drill further to total depth of 5,625 m.

GAIL Begins Dabhol-Bengaluru Gas Pipeline

GSPC Invites Bids for EPC Contractor in Mundra Terminal

Bengaluru: State-owned gas utility GAIL India Ltd has commissioned gas pipeline from the just operationalised Dabhol in Maharashtra LNG terminal into Bengaluru that promises to change the energy landscape of the region.

The 1,000-km pipeline will feed industries at Belgaum, Dharwad, Gadag, Bellary, Davanagere, Ramanagaram and Petroleum Minister M Veerappa Moily Chitradurga, Tumkuyr, Bengaluru who have till now been using costlier and polluting liquid fuels like naphtha and diesel as feedstock.

Ahmedabad: Gujarat State Petroleum Corporation (GSPC) has invited global bids to select an Engineering Procurement and Construction (EPC) contractor for its LNG re-gasification terminal proposed at Mundra in Gujarat.

The 5-million-tonne-per-annum (MMTPA) LNG terminal to be set up by GSPC LNG Limited (GLL), a joint venture of GSPC and Adani group, will be set up with an estimated investment of ` 40 billion. The terminal capacity would be expandable upto 10 MMTPA. GSPC has 50 per cent stake holding in the JV, while Adani group holds 25 per cent, remaining 25 per cent will come from a strategic investor.

The Dabhol-Bangalore pipeline was laid with an investment of ` 4,500 crore and is designed to handle 16 mmscmd of natural gas.

During commissioning of the gas pipeline, Petroleum Minister M Veerappa Moily said that with the gas coming in, the devil of pollution will disappear from the City of Gardens. Gas will help the state power generation utility save ` 8 billion annually by reducing cost, improving efficiency and drastically cutting down pollution caused by using liquid fuels. The pipeline will be extended to Mangalore this year and further to Kochi in Kerala by end of next year.

GSPC has been scouting for a strategic investor for its LNG project, after Essar group — the third partner with a 25 per cent stake in the venture — exited from the proposed LNG (liquefied natural gas) terminal. In September 2012, GLL had invited global bids to select a EPC contractor for the LNG storage tanks, to be set up at its proposed LNG re-gasification terminal at Mundra.

The LNG terminal is designed to have two LNG storage tanks. It will have LNG receiving, re-gasification and gas evacuation facilities. The company has awarded the front-end engineering and design (FEED) contract to Tractebel of Belgium.

India and Kazakhstan Agree to Enhance Mutual Corporation in Oil Sector New Delhi: India and Kazakhstan have jointly agreed to enhance mutual corporation in hydrocarbon sector during the 10th meeting of the IndiaKazakhstan Inter-Governmental Commission (IGC) on Trade, Economic, Scientific, Technological, Industrial and Cultural held on 8-9 January 2013 in New Delhi.

M Veerappa Moily, Minister of Petroleum and Natural Gas, led the delegation from India. The Kazakh side at the IGC meeting was led by Bulat Akchulakov, Vice Minister of Oil and Gas, Republic of Kazakhstan. The two Ministers signed IGC Protocol after conclusion of the India-Kazakhstan IGC meeting. The two sides had reviewed progress with regard to various decisions taken at the 9 th Inter-Governmental Commission meeting held in Astana on 12 th October 2011.

The deliberations of the Inter-Governmental Commission were marked by cordiality and warmth, which are characteristic of the traditionally close

and friendly ties prevailing between the two countries. This discussions took place in 20 sectors of cooperation like Energy, Trade, Agriculture, IT, Science & Technology, Mines etc.

Both the sides agreed that the current level of bilateral trade is not commensurate with the potential existing between the two countries and called for conscious efforts to increase Indo-Kazakh trade through the Joint Working Group on Trade and Economic Cooperation and the India Kazakh Joint Business Council.

The meeting of the Joint Working Group on cooperation in hydrocarbon sector was held along with the IGC meeting. The next meeting of the Joint Working Group will be held in Kazakhstan. The dates will be agreed through diplomatic channel. Both sides noted with satisfaction the decisions of the second meeting of the India-Kazakhstan Joint Working Group on Trade and Economic Cooperation held in Astana on 19-20 July, 2012.

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RIL-BP Seek Oil Ministry Approval on KG Block Enhancement Plan Mumbai: Reliance Industries Limited (RIL) and BP Group have sought approvals from OIl Ministry for KG D6 block enhancement plan which entails an investment of USD 5 billion and developing of around 4 trillion cubic feet of gas, during the meeting of Bob Dudley, BP Group Chief Executive and Mukesh Ambani, Chairman and Managing Director of RIL to Petroleum and Natural Gas Minister Veerappa Moily.

the government that no performance audit would be carried out and only audit under Article 1.9 of production sharing contract (PSC) would be done.

During their meeting, both BP and RIL expressed their plan to invest in a series of projects to develop around 4 trillion cubic feet of discovered natural gas resources from the block. This plan, when implemented, would entail a potential total investment in excess of USD 5 billion over the next three to five years. They updated the Minister of their joint future plans in India, including the KG-D6 block enhancement plan designed to increase production from the block. The issue of audit by the Comptroller and Auditor General (CAG) also reportedly came up for discussion and RIL pointed out to the written assurance given by

Ambani also informed Moily that the BP and RIL partnership will focus on finding more hydrocarbons and addressing the complexities of the geology along the East Coast of India. They were confident that development of the existing discoveries, together with exploration prospects in KG-D6 has the potential to enhance domestic production significantly.

Moily assured both Dudley and Ambani on their request to expedite approvals that the govt will do the needful to fast track these projects and help them attain economic viability.

The JV has already submitted to the government for approval the field development plan for the R-Series project.

CCI to Clear 39 Oil & Gas Fields: Montek New Delhi: The Union Govt is likely to go ahead with further exploration proposals of several 39 oil and gas fields that are stuck for want of defence clearance, said Planning Commission Deputy Chairman Montek Singh Ahluwalia.

The Cabinet Committee on Investment (CCI) considered Defence Ministry declaring 7 blocks Planning Commission Deputy including Reliance Industries’ KG-D6 gas block Chairman Montek Singh Ahluwalia and its gas discovery area NEC-25 as ‘No-Go’ area and stringent conditions being imposed on exploring in another 32 blocks.

The CCI had earlier advised both the Ministries of Defence and Oil & Gas to sort out issues like exploration area overlapping with proposed Naval base or being close to missile launching and Air Force exercise area, within one month. The panel, headed by Prime Minister Manmohan Singh, is to then consider giving the blocks go-ahead for oil and gas exploration and production. Officials from

ministries of defence and petroleum have sorted out issues at majority of the 39 blocks. Defence ministry has declared 7 blocks including RIL’s KG-D6, which has been in production since September 2008, and its gas discovery block NEC25, as ‘No-Go’ areas for oil and gas exploration and production activities.

It imposed stringent conditions for another 32. The CCI had asked the Ministry of Defence and the Oil Ministry to sort out differences over the seven block in one month, and for the 32 areas in three months.

Originally, the defence ministry had declared 14 blocks as ‘No-Go’ areas as they over-lapped or were close to proposed Naval base or missile launching range/ air force exercise area.

But the defence ministry later relented and agreed for exploration to be permitted in 7 blocks in Mahanadi basin. One more block which was previously objected to by the Commerce Ministry too has been cleared, bringing down the number of blocks awaiting clearances from 47 to 39.

NTPC’s Jharkhand Power Project Gets Cabinet Nod New Delhi: National Thermal Power Corporation’s (NTPC) 1,980-MW North Karanpura Super Thermal Power Plant in Jharkhand has got Cabinet approval after the Cabinet Committee on Investment (CCI) cleared the proposal of the Ministry of Power for setting up the power plant.

it said, had 6 billion tonnes of coal reserves. However, the power ministry opposed relocation.

A Group of Ministers (GoM) had earlier suggested implementing the project at the same location for 35 years.

Power Ministry said that the CCI also agreed to restore the original coal linkage for the project that has been cleared for setting up in the vicinity of Tandwa town, district Chatra in Jharkhand. The coal supply for project would be made available in the 13 th Five Year Plan (2017-2021), it said.

The power ministry had proposed restoration of the original coal linkage for the project at the present site, while NTPC would provide an undertaking that the plant would only run for 35 years as recommended by the B K Chaturvedi committee.

The Coal Ministry had withdrawn the coal linkage for NTPC’s ` 14,000 crore project in 2008 and wanted its relocation to another site in the district, which,

The first project to be set up by NTPC in Jharkhand will be on a pit-head with environment friendly super-critical technology.

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news Indian LNG Market Remains below Expectations New Delhi: Indian natural gas market may not be of a scale that many had estimated, and the reduced domestic gas production is also likely to lower the growth of the Liquefied Natural Gas (LNG) market, according to global energy consultancy Wood Mackenzie. Global LNG suppliers looking to sell into Asia may shift their focus on the combined South East (SE) Asian markets – predominantly Indonesia, Thailand, Malaysia and Singapore – as the LNG appetite of these markets increase.

counter-intuitively to some, reduced gas production will also lower the rate of LNG market growth in India.

The combined SE Asian LNG markets will account for a third of overall Asian LNG demand growth by 2025, growing by 45 million tonnes per annum (mmtpa).

However, the rate of India’s LNG market growth may not be as sizeable as once thought, growing by 20 mmtpa within this timeframe.

Browne added that this decline in gas output will constrain gas availability to the Indian market, mainly impacting the power sector in the medium term. In the longer term, reduced production will preclude the development of greenfield fertiliser production as it is not economical to develop facilities purely based on LNG imports.

Nicholas Browne, Senior Gas Market Analyst at Wood Mackenzie, said that it is expected the India LNG market loses momentum domestic gas production and this is expected to limit the development of the gas market. Perhaps

The energy consultant further said that gas production from the D6 field would continue falling, reducing the overall gas availability for Indian gas production.

Production from Reliance’s D6 block has fallen to 11 billion cubic metres (bcm) last year from a peak of 20 bcm in 2010.

He further added that LNG demand growth in other industrial sectors is further limited by reduced economic growth expectations.

India to Receive Gas from Turkmenistan by 2017-18 GSPC Seeks LNG Price of KG Gas New Delhi: The USD 9 billion Turkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline to help supply 38 mmscmd of gas to India is expected to receive gas from Turkmenistan by 2017-18. The ministry of petroleum and natural gas has said that the commercial operation of the TAPI gas pipeline is set to commence by 2017-18.

The minister of state for petroleum and natural gas, P Lakshmi said in a written reply to the Lok Sabha that after completion, the TAPI project envisages supply of 38 million metric standard cubic metre per day (mmscmd) of gas to India. So far, the inter-governmental agreement, gas pipeline framework agreement and the gas sales purchase agreement have been finalised. Commercial operation of TAPI project is expected to commence in 2017-18.

Recently, the Centre had given clearance for setting up of a special purpose vehicle for the TAPI pipeline project, allowing GAIL to be a part of it. Out of the total length of the pipeline, 144 km will be through Turkmenistan, 735 km through Afghanistan and about 800 km via Pakistan. According to the understanding between the countries, the Dubai-based SPV, TAPI Ltd, would scout for a consortium leader to execute the project. As per the agreement, the initial equity contribution of India in the proposed SPV would be USD 5 million.

Ahmedabad: Taking a cue from Reliance Industries, Gujarat-Government firm GSPC is seeking to price natural gas it will produce from KG basin block at a rate indexed to cost of imported liquid gas (LNG). Gujarat State Petroleum Corp Ltd (GSPC) wants to price gas that it will produce from Deen Dayal West (DDW) gas field in block KG-OSN-2001/3 by third quarter of 2013, at a minimum of USD 8.50 per million British thermal unit, excluding local taxes and margin.

GSPC, owned by the Gujarat Government, will produce a maximum of 5.24 million standard cubic meters per day of gas from the offshore DDW gas field.

The gas will land at Mallavaram, near Kakinada in Andhra Pradesh, and can be ferried to customers up to Gujarat through Reliance Gas Transportation Infrastructure Ltd’s East-West pipeline.

The company in an advertisement issued in national and regional dailies invited bids from potential consumers at price formula at which Petronet LNG gets liquefied natural gas (LNG) from Qatar on a long-term contract.

GSPC sought 12.67 per cent of the average Brent crude oil price plus USD 0.26 per million British thermal unit. It asked users to quote a positive or negative number, termed as ‘V’, that can be added to this pricing formula.

Cairn India Commences Drilling in Rajasthan Block Jaipur: After a four year hiatus, Cairn India has commenced exploration drilling programme in the Rajasthan block. This will help the joint venture (Cairn, ONGC) to realise the basin production potential of 300,000 barrels of oil per day from the Rajasthan block.

The joint venture is currently producing 170,000-175,000 bopd from the Rajasthan block with a strong focus on exiting the year FY 2013-14 at a production rate of 200,000-215,000 bopd from the block.

On January, the operating committee of the Rajasthan oilfields, comprising nominees of Cairn India and ONGC, was asked to submit a proposal to scale up output from the fields by the block’s Management Committee. The management committee comprises the Directorate General of Hydrocarbons and Petroleum Ministry representatives as well as nominees of the contractors (Cairn India and ONGC).

Cairn holds 70 per cent stake in the block, while ONGC has 30 per cent.

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Oil & Gas Players Seek Tax Incentives from 2013 Budget New Delhi: The oil and gas industry now faces the prospect of declining domestic oil and gas production, lack of interest by international investors and absence of a proper regulatory mechanism that has led to a slowdown in domestic as well as foreign investments in both upstream and downstream projects.

Lack of effective response from international investors to the last few rounds of the New Exploration Licensing Policy (NELP) and continued disputes over the Production Sharing Contracts (PSC) has made it desirable to adopt necessary changes to global players in this sector.

The continued decline in gas production from Reliance Industries Limited’s (RIL) KG-D6 has further aggravated the situation among infrastructure sectors across the board. Given the increased domestic demand for natural gas, it is imperative to develop unconventional nature gas resources like CBM, shale gas as well as robust natural gas infrastructure. In order to boost domestic oil and gas production and infrastructure, there is a need for large capital investments and state of art technology. Given the lengthy gestation period and investment

FM to Consider UAE Offer on Oil Reserves

Finance Minister P Chidambaram

New Delhi: The 1.33 metric tonne (mt) strategic storage at Visakhapatnam is scheduled to be completed this year at a cost of ` 1,038 crore.

The ` 732-crore, 1.5-mt Mangalore storage will be completed by December 2013, while the third storage at Padur, with a capacity to stock 2.5 mt oil and entailing an investment of ` 993 crore, will be ready by April 2014.

Finance Minister P Chidambaram will have to make a budgetary allocation of around ` 20,000 crore for the oil ministry to fill up these 5.3-mt strategic crude reserve. Alternatively, the government will have to consider the offer made by Abu Dhabi National Oil Company to use the facility for free and pay only for the operational and maintenance costs. The UAE firm, however, has given the government the first right to use the crude in case of disruption in supplies.

However, the Abu Dhabi firm’s proposal to use the facility for free has sparked concern. The ministry had hoped that the Gulf-based firm would pick up an equity stake in Indian Strategic Petroleum Reserves Ltd (ISPRL), the owner, or use the facility on rent.

India, which imports about 80 per cent of its crude requirements, is building underground storages to store about 5.33 mt oil, which will meet the country’s need for 13-14 days. At present, the country has a 3-3.5 mt reserve held by Bharat Petroleum Corporation Ltd, Hindustan Petroleum Corporation Ltd and Indian Oil Corporation.

The government is considering raising the storage capacity to 15 mt to cover the requirement for 45 days in a phased manner. www.oswindia.com

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risk involved in this sector, industry is looking forward to fiscal incentives and stability in forthcoming budget which can encourage increased investment in this sector.

In order to boost production of natural gas, the tax holiday available for profits from production of natural gas from NELP-VIII and CBM-IV blocks should be extended to pre-NELP & other NELP/ CBM rounds.

Given that India depends largely on foreign oilfield service (OFS) contractors for its E&P activities, continuation of presumptive taxation regime on technical services provided by OFS contractors should be clarified.

Further, issue of availability of investment linked tax incentives to city gas development (CGD) network remains unresolved. In view of significant investment and lengthy gestation period associated with CGD networks, Government should clarify its stand regarding availability of such incentives to CGD network.

HPCL, Shapoorji Pallonji Alliance for LNG Terminal Mumbai: Hindustan Petroleum Corp Ltd (HPCL) and SP Ports Pvt Ltd, a unit of Mumbai-based infrastructure major Shapoorji Pallonji have formed a 50:50 joint venture (JV) to set up the liquefied natural gas (LNG) import terminal at Chhara in Junagadh, Gujarat at a cost of ` 50 billion.

SP Ports is already developing a greenfield, all weather, direct berthing port in Junagadh district. HPCL and SP Ports are carrying out a detailed feasibility study for establishing technical and commercial viability of setting up a LNG import and re-gasification terminal of 5 million tonnes per annum capacity at the proposed Port.

Gujarat already has two functional ports at Dahej and Hazira. A third one is under planning by Gujarat State Petroleum Corp (GSPC) and Larsen & Toubro (L&T) at Mundra. The Chhara terminal would be the fourth in the state and may take a minimum of three years to build.

Essar Wants Entire Access of Cambay Basin Ahmedabad: Essar Energy wants to have entire access of the Mehsana block in the eastern flank of the Cambay basin of Gujarat from its partner, Oil and Natural Gas Corporation (ONGC). Essar owns 70 per cent stake in the block and has approached ONGC to take on the entire area on a ‘sole risk’ basis, under which it make all the investments for developing the block and assume responsibility for paying all government levies and cesses.

Essar is currently producing crude oil from one of its fields, being sold to a government-owned refinery. Two more discoveries in the block have been notified and are being assessed for commercial viability. The block was allocated prior to the New Exploration and Licensing Policy. Essar had signed a 25-year production sharing contract with the Union government and ONGC in July 1998.

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news LNG Demand to Rise 4.6% annually over 15 years New Delhi: The demand for liquefied natural gas (LNG) is forecast to rise by 4.6 per cent annually over the next 15 years.

According to organisers of an industry event, LNG is one of the fastest growing segments of the gas market, with industry research suggesting that LNG demand is forecast to rise by 4.6 per cent annually over the next 15 years.

In the Middle East and North Africa (MENA) region alone, the International Energy Agency (IEA) expects demand for natural gas to rise by 79 billion cubic meters (bcm) or 20 per cent between 2011 and 2017, outstripping incremental supply in the region by 7 bcm as low gas prices encourage higher consumption

by the utilities and transportation sectors. On the customer side, demand from the Asia-Pacific region for LNG from the MENA region is strong – particularly from Japan, Korea and India. This trend looks like it will continue through 2020 with a significant increase in demand from China and Korea expected.

To meet these growing demands, the infrastructure underpinning global trade in LNG – storage tanks, terminals, tankers – will need to grow and develop in tandem.

The growth of the global LNG market is spurring innovation in the industry as companies think bigger but leaner at the same time.

Oil India Seeks Partner for Rajasthan Heavy Oil Find India Proposes Hydrocarbon Pipeline from Kazakhstan Jaipur: Oil India Ltd is looking for a technical partner to help bring to production its find of heavy oil in the NELP onshore block in Rajasthan.

This is after an experiment with PDSVA Venezuela failed to make headway in flowing similar crude oil from its Rajasthan nomination field (area given to national oil companies prior to the licensing rounds).

Oil India and its partner GeoGlobal Resources struck oil in the block RJONN-2004/2 on December 17 last year.

New Delhi: India has proposed a hydrocarbon pipeline that will bring fuel through five-nation route. India unveiled the concept of the pipeline, which in future could be extended to Russia, during a meeting between External Affairs Minister Salman Khurshid and his recently visiting Kazakh counterpart Erlan Idrissov. The two Ministers will revisit the idea when they will meet twice in the coming months — first on the sidelines of the Istanbul process meeting on Afghanistan in Almaty and later during a stand-alone visit by Khurshid to the Kazakh capital of Astana.

The NELP (New Exploration Licensing Policy) block initially flowed 3.5 barrels of oil a day (bopd) of heavy oil.

The proposed pipeline would cover about 1,500 kms (no study has yet been done), thus making it longer than the planned Turkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline which will serve as the role model. It will head from the former Silk Road caravanserai city of Shymkent, known today for oil refining, and enter Uzbekistan.

From there it will go to Afghanistan and then follow the route to be taken by the TAPI pipeline into India via Pakistan. Most hydrocarbon pipelines from Central Asia are on an east-west axis. This pipeline will, like TAPI, be on a north-south axis, providing a new route to South Asia for hydrocarbons extracted from Central Asia.

Welaptega Awarded Mooring Inspection in India

Dabhol Plant Shuts Down Lack of Fuel

Mumbai: Welaptega Marine has been awarded a mooring inspection and fitness for purpose evaluation on Dhirubhai-1 floating production storage and offloading (FPSO) facility located in the Bay of Bengal, off the eastern coast of India.

Mumbai: Dabhol power plant has completely shut operations being hit severely by the decline in production of gas at Reliance Industries’ KG-D6 Blocks. The 1,967-MW power plant, which is now run by Ratnagiri Gas and Power (RGPPL), was allocated 7.6 mmscmd of KG-D6 gas. However, since quite some time there has been no supply. Due to gas shortage, the company was generating only about 50 per cent of its 1,967 MW capacity for the last few years. Since January 2013, the plant production has not only dropped but shut operations several times due to want of gas.

The block is located 400 km from Cairn India’s Barmer oilfields and 120 km West of Bikaner in the Bikaner-Nagaur Basin. This NELP VI block lies north-east of OIL’s discovered nominated fields.

A team of specialist engineers will deploy Welaptega’s suite of visualization and inspection technologies including the High-Definition 3D Video (HD3DV), 3D Modeling (3DM), Opticial Chain Measurement System (CMS), Subsea Chain Measurement Caliper and the Rope Measurement System (RMS).

Welaptega will work with offshore engineering firm BPP-TECHin the UK to establish the Fitness for Purpose Evaluation using data on operational history, met-ocean conditions, design, installation and maintenance of the mooring spread.

The inspection of the FPSO’s mooring system is a rolling annual program in which three mooring lines will be inspected on the facility in each year. FPSO Dhirubhai-1 is a converted oil tanker operating at 1200 m water depth with a production capacity of 60,000 bpd.

To run the project at full capacity, the company needs 8.5 mmscmd gas of which 7.6 mmscmd should come from Reliance while the remaining from ONGC through GAIL. Since the last two years, the company is facing gas shortage. In FY12, the plant received only 6.6 mmscmd of gas, and in FY13 till January, it received only 3.2 mmscmd. This has resulted in a generation loss of around 7,500 million units. Currently, the plant supplies 95 per cent of the power generated to Maharashtra. Of the remaining 5 per cent, the company supplies 2 per cent of the power generated to Dadra & Nagar Haveli, 2 per cent to Daman & Diu and 1 per cent to Goa. This will definitely have an impact on the power supply to these regions, especially Maharashtra.

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ONGC Plans Oil Exploration in Bengal Kolkata: Oil and Natural Gas Corp (ONGC) is set to start its maiden exploratory drilling on an onshore oil block in West Bengal.

Exploration Licensing Policy, or Nelp VII, in 2008. The production sharing contract was signed in December 2008, while the exploration licence was granted a year later. The block covers an area of 1,069 sqkm.

The company has decided to dig two exploratory wells in villages Ladhi and Dangi near Chakaliya in Uttar Dinajpur district of West Bengal for which the company has just applied to the state government for necessary approval.

Bharat Heavy Electrical Ltd’s Pollution Control Research Institute at Haridwar has already completed the environment impact assessment on behalf of ONGC for this onshore block.

The area in Uttar Dinajpur falls under Block PA-ONN-2005/1 of the Purnea basin, which ONGC bagged under the seventh round of auction under the New

Exploratory drilling is undertaken to establish the presence of hydrocarbons indicated by seismic survey and interpretation of data.

Paradip Refinery to be Commissioned in Nov 2013

Hardy to Increase Stake in Offshore India Gas Project

New Delhi: Indian Oil Corp’s (IOC) under-construction grassroot refinery at Paradip is likely to be completed in November 2013, Minister of State for Petroleum Panabaaka Lakshmi told the Lok Sabha.

Mumbai: Partners in the Dhirubhai 33 gas discovery offshore western India are in discussions over possible development. Reliance operates the joint venture for the surrounding block GS-OSN-2000/1 (GS-01). Hardy Oil and Gas has a 10 per cent interest, but hopes to raise its participation.

In a written reply, the minister said IOC’s 15 million metric tonnes per annum (MMTPA) refinery at Paradip in Odisha is at an advanced stage of construction and is expected of completion in November 2013. She added that IOC has informed that construction of the Paradip Refinery has generated employment for about 10,000 skilled and unskilled people of nearby areas thereby impacting their social and economic life.

A field development plan was submitted to India’s government last year.

The plan calls for an unmanned platform with several dry tree wells, a multi-phase pipeline to shore, and onshore processing and export facilities.

The GS-01-B1 well, drilled in 2007, flow-tested 18.6 MMcf/d of gas and 415 b/d of condensate through a 56/64-in. choke, with a flowing tubing head pressure of 1,346 psi (93 bar).

The commissioning deadline for the ` 30,500 crore project has already been revised once from November 2012 to September 2013. According to IOC, the main reason for the delay is the delay in completing the captive power plant by state-run BHEL.

The GS-01 license is in the Gujarat-Saurashtra offshore basin, northwest of the Bombay High oil field, in water depths of 80-150 m (262-492 ft). The retained discovery area spans 600 sq km (231 sq mi).

Govt to Invest on Setting up CNG Plants in Kerala

HPCL to Build Oil Refinery in Rajasthan

Thiruvananthapuram: In a bid to boost the struggling public transport sector of Kerela, the Union Government has agreed to invest around ` 100 crore to set up CNG plants in the state.

New Delhi: HPCL, the state-owned oil company, has proposed to set up a 9 million tone (mt) oil refinery as well as petrochemical complex at a cost of ` 37,000 crore at Barmer in Rajasthan.

In a meeting with Kerala Chief Minister Oommen Chandy and Transport Minister Aryadan Mohammed, Union Petroleum Minister M Veerappa Moily has given assurance to set up CNG plants in this state.

The company’s board has approved this decision and also approved the company’s plans to expand its Bhatinda refinery in Punjab to 11.2 mt from the present capacity of 9 mt. The ` 21,500 crore Bhatinda refinery is a joint venture operation between HPCL and Mittal Energy Investment Pte Ltd and was commissioned last year. Both companies hold an equal stake of 49 per cent each in the refinery and the remaining 2 percent is held by financial institutions.

The purpose of the meeting was to discuss about the Kerala State Road Transport Corporation which is incurring monthly loss ranging from ` 70 crore to ` 90 crore.

Chandy said that the Union Petroleum Minister has assured the state to sanction ` 100 crore to Kerala State Road Transport Corporation (KSRTC) to set up CNG plants and it will great help to the struggling public transport sector of the state. .

Half of the supply of crude oil for the Barmer refinery will be provided by the nearby Cairn India oilfields, while the remaining will be imported. Previously, ONGC had committed to building the Barmer refinery back in 2005. However, HPCL proposed to take ownership of 51 per cent stake in this project, while ONGC continues to show interest in having a stake in this project.

At present, the Corporation has 5,555 schedules and 6,179 buses. The average earnings per km works out to round about ` 30.83 and the average earnings per bus (EPB) works out to ` 10,049.

30 per cent of the stake in Barmer oilfields is under ONGC’s ownership, while Cairn India owns the remaining 70 per cent. Its current production capacity is around 175,000 barrels per day and can go up to 300,000 bpd.

www.oswindia.com

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news Swiber Announces Completion of its First Floatover Oil India Pays ` 518 cr dividend to Government Operation in India New Delhi: Oil major, Oil India Ltd (OIL)

has paid a total dividend of ` 518.65 crore to the government of India during the financial year 2012-13.

New Delhi: Swiber Holdings Limited, a world-class integrated construction and support services provider to the offshore industry, has announced the successful completion of its first floatover operation with the B-193 Field Development project in India for Oil and Natural Gas Corporation Ltd (ONGC), the country’s national oil company,.

The extensive scope of work for this complex project involved floatover installation of a 13,000 MT AP process platform and an 8,000 MT AQ living quarter platform, as well as installation of bridges and flares. Fabrication of the topsides, jackets and other structures was undertaken by a consortium partner at their yard in Malaysia.

With topside weights increasingly exceeding floating crane lifting capacities, floatover installation has emerged as a reliable and cost-effective alternative. The Group utilised its Derrick Pipelay barge Swiber PJW3000 along with the 2 floatover barges Holmen Atlantic and Holmen Pacific supported by several other support vessels for this project, located at offshore Mumbai in India.

IOC Plans Major Expansion in FY14 Kolkata: Indian Oil Corporation (IOC) has proposed on expanding its network to invest ` 10,000-11,000 crore in the forthcoming fiscal year.

R S Butola, Chairman, IOC

R S Butola, Chairman, IOC expressed, that the company will spend around ` 10,000-11,000 crore a year to expand its network, so that is the expenditure that the company will incur in FY14.

Butola further stated that the firm will be spending ` 56,000 crore in the next five years on constant price basis in the 12 th Plan period.

He stated that IOC would also be spending ` 3,500-4,000 crore a year on non-plan areas.

He stated that IOC has some blocks in Libya, however, these are small and there is no production, only exploration.

“So, production has not been affected. Exploration activity is also at a very preliminary level,” Butola further maintained.

S K Srivastava, Chairman and Managing Director of OIL

S K Srivastava, Chairman and Managing Director of OIL, has handed over the cheque of ` 518.65 crore towards interim dividend at 110 per cent for the financial year to M Veerappa Moily, Minister for Petroleum and Natural Gas.

The government holds 68.43 per cent stake in OIL, the second largest public sector oil and gas exploration and production company in the country.

OIL is producing at the rate of around 3.72 MTPA of crude oil and 7.22 MMSCMD of Gas from its fields.

OIL has exploration and production acreages of over 1,60,000 sq km pan-India and overseas.

High Crude Prices to Increase Subsidy Bill B eyond Ta rg et Mumbai: Ahead of Union Budget that is likely to focus on spurring growth, the Economic Survey 2012-13 said, “Addressing the key fiscal risk of petroleum subsidies is critical in better fiscal marksmanship.” The subsidy bill will overshoot the target of ` 1.79 lakh crore in this financial year due to higher crude oil prices.

The Government has pegged the oil subsidy at ` 43,580 crore, food subsidy at ` 75,000 crore and fertiliser subsidy at ` 60,974 crore, taking the total subsidy bill to 1,79,554 crore in 2012-13.

“With recent reforms in diesel prices and efforts at expenditure reprioritisation, the medium-term fiscal consolidation plan is credible and could yet again yield macro-economic dividends in terms of higher growth and price stability,” said survey.

Earlier, in a bid to check the increasing subsidy burden, the government had raised diesel prices and capped the number of subsidised cylinders at six per household in a year in September 2012.

Meanwhile, IOC has implemented 80-85 of the MB Lal committee’s recommendation on safety while it was 72 per cent for the entire industry.

In January 2013, the Government also allowed oil marketing companies to raise diesel prices in small measures periodically. However, in order to protect household budgets, it simultaneously raised the annual LPG cap from six to nine cylinders.

Raj Kr Ghosh, Director, IOC expressed that the company is also planning to engage an independent external agency for handholding support to encourage safety culture in the organisation.

But with international crude oil prices averaging at USD 107.52 a barrel in the first three quarters this fiscal, the Government’s payout to keep the domestic retail price of auto, cooking fuels and fertilisers will see a substantial rise.

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www.oswindia.com

3/22/2013 8:26:01 PM

CCEA to Form Policy to Convert Underground Coal Gujarat Gas Posts 5% Growth in Net Profit to Gas Ahmedabad: Gujarat Gas Company Ltd (GGCL) has posted 5 per cent rise in New Delhi: With the country facing acute fuel shortage to keeping economical growth in pace, the Cabinet Committee on Economic Affairs (CCEA) is likely to form a new policy on converting the underground coal to gas.

net profit for the calendar year 2012, ended December 31, 2012, as compared to the corresponding period the year before. The company has also reported 29 per cent rise in annual sales. The consolidated net sales for 2012 were ` 3,066 crore (` 2,381 crore). The total volume of gas sold during the period was 1,157 million standard cubic metres, or mscm, (1,246 mscm).

The underground coal gasification refers to a method of changing coal that is still in the ground Sriprakash Jaiswal, Coal Minister to a combustible gas that can be utilised for various purposes, including power generation.

The impact on profits due to increase in gas cost in the previous year was mostly mitigated in 2012. The total volume of gas sold during the quarter was 270 mscm (314 mscm). Volumes in the industrial segment have been undergoing a churn with increasing price of gas.

Earlier this month, the Coal Ministry had month moved a Cabinet note on a policy for underground coal gasification and received reviews from the various ministries on the matter.

The company connected 7,300 residential customers and converted about 5,100 vehicles to CNG during the quarter in addition to commissioning additional volumes in the industrial sector.

Sriprakash Jaiswal, Coal Minister also urged cooperation of countries like South Africa for underground coal gasification technologies.

The company had received authorisation from the sectoral regulator Petroleum and Natural Gas Regulatory Board (PNGRB) for the city gas distribution areas of Surat, Bharuch and Ankleshwar.

The demand and supply deficit of coal which has increased to 161.5 million tonnes (MT) in the previous fiscal, is expected to reach 200 million tonnes by 2016-17.

L&T Bags Petronas’s Offshore Contract Mumbai: Larsen & Toubro (L&T), the Indian multinational conglomerate, has signed a contract with PETRONAS Carigali Myanmar (Hong Kong) Limited in Yangon, Myanmar for executing an offshore engineering, procurement, construction, installation and commissioning project valued at over USD 100 million.

The order enlarges L&T’s footprint in the competitive hydrocarbon upstream market in South East Asia, and has already been included in L&T’s order inflow disclosure.

The Yetagun North Field is operated by PETRONAS Carigali Myanmar (Hong Kong) Limited with PETRONAS Carigali Myanmar Inc, Myanma Oil and Gas Enterprise, PTTEP International Ltd and JX Nippon Oil Exploration (Myanmar) Ltd as its partners.

The 19-month project includes supplying an offshore wellhead platform and subsea pipeline to be installed in a water depth of 108 meters. The scope also includes host tie-in works on an existing platform in the Yetagun complex.

L&T’s facility in Kattupalli on the East Coast of India will undertake the fabrication work for the project.

L&T is one of the few contractors in the world with complete in-house engineering, procurement, fabrication and installation capability in the hydrocarbon upstream sector. This integration of resources and end-to-end capability is of special relevance to several large developments being planned by global majors in South East Asia. www.oswindia.com

India News.indd 38

GGCL, a subsidiary of BG Group plc (65.12 per cent), currently distributes approximately 3.2 mscmd of natural gas.

BPCL Selects OptaSense to Monitor Bijwasan Pipeline in UP Mumbai: State-run fuel retailer Bharat Petroleum Corporation Limited (BPCL) has selected the real-time intelligence company OptaSense, a QinetiQ company, to protect the Bijwasan pipeline in India.

The pipeline is owned and operated by BPCL and runs from Kota, Rajastan to Mathura, Uttar Pradesh.

The contract with OptaSense is for its Third Party Intervention (TPI) application, and has been awarded through the Indian subsidiary of OptaSense’s distribution partner, Optilan.

The project will protect approximately 200 km of pipeline and BPCL will be implementing the system on further pipeline lengths upon successful completion of this phase. When completed the system will comprise approximately 20,000 virtual microphones along the pipeline and brings the total amount of pipeline monitored in India to approximately 1,000 km making OptaSense by far the largest operator in the region. OptaSense is worldwide leaders in creating distributed fibre sensing solutions, which use existing fibreoptic cables running alongside pipelines and other installed infrastructure to act as virtual microphones. These microphones are monitored and analysed in real-time, to allow users to ‘hear’ if pipeline are under threat – the real time nature of the system will enable BPCL to prevent damage to their pipeline increasing the assurance of product supply.

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3/22/2013 8:26:03 PM

news CAG Audits on Govt Role in Fixing Oil & Gas Prices New Delhi: Comptroller and Auditor General (CAG), the national auditor, has started a comprehensive scrutiny of government’s role in fixing prices of oil products and supply of scarce natural gas, particularly from Reliance Industriesoperated KG-D6 block, to various consumers with an objective to ascertain the implications on the exchequer.

The Comptroller and Auditor General (CAG) will conduct two separate performance audits; one on the supply and pricing of natural gas and the other is related to pricing mechanism of major petroleum products, including petrol and diesel.

Through this audit, the CAG will also examine performance of petroleum, power and fertiliser ministries, which are actively involved in gas pricing and supply issues. CAG’s performance audit is considered the most comprehensive review which includes the auditor’s independent assessment of economic, efficient and effective operation of an organisation, programme or scheme.

The performance audit of supply and pricing of natural gas is covering the period from 2007-08 to 2011-12, which will cover the pricing of RIL’s KG-D6 gas, its allocation to various consumers and supply cuts due to decline in gas production.

Other audits undertaken by CAG are ‘financial’ and ‘compliance’ audits. In the first meeting of performance audit for supply and pricing of natural gas, state-owned Gail India suggested to expand the audit scope to private companies involved in supply of gas. The first meeting, which is also called entry conference, was attended by representatives of CAG, downstream regulator, petroleum, power and fertiliser ministries and executives of Gail, ONGC and Oil India.

Vedanta Advised to Acquire Cairn Energy

Oman, India Agree in Tackling Oil Spillage

New Delhi: A number of investment bankers have, over the past few weeks, made presentations to top officials of Cairn India, owned by Vedanta’s Anil Agarwal, on global acquisition opportunities in the oil & gas sector.

Anil Agar wal, Founder and Executive Chairman, Vedanta Group

One of the options suggested to Cairn India was buying the London Stock Exchange (LSE)-listed Cairn Energy, which has 50 production blocks across the world and a 10 per cent stake in Cairn India (worth ` 5,818 crore).

The suggestions were made after Cairn India sought bankers views on how it could deploy its extra cash in oil & gas assets across the world. The company has USD 2.7 billion ( ` 14,670 crore) of cash and is expected to generate cash flows - after meeting all the capital expenditure requirements of the Rajasthan block - of USD 1 billion every year for the rest of this decade.

The presentations were made to the firm’s top management, led by P Elango, Director and CEO, Cairn India. Vedanta took over Cairn India in 2010 for USD 8.6 billion from Cairn Energy, which has a varied shareholding structure, without any single promoter.

Agarwal has earlier said that Vedanta was expecting USD 10-12-billion earnings in the next two-three years and that he would bid for oil and gas assets in India, besides some coal assets, to deploy the group’s excess cash.

The presentations to Cairn India management come against the backdrop of global brokerage house CLSA recommending the firm look at buying Cairn Energy.

CLSA had also said the acquisition of Cairn Energy would help Cairn India soothe investor concerns, such as limited growth in single-asset play like Rajasthan, rise in tax on oil, and lack of clarity on investment in cash.

New Delhi: The Sultanate of Oman and India can play a crucial role in tackling oil spillage in the Arabian Sea effectively given the two friendly nations enhance joint operations in an active way, according to Donny Michael, Deputy Inspector General of the visiting Indian Coast Guard Ship ICGS Samudra Prahari, the first vessel fully dedicated to confronting oil spillage in the region.

The two sides have already exchanged their views and had held discussions to this effect. Accordingly, chances are both would agree on knowledge sharing and expertise management between them on a mutually beneficial basis.

The ICGS Samudra Prahari has, apart from discharging the requirements related to ICG Charter of Duties, tackled four major oil spills in the last nearly two and half years, one firefighting operation and one SAR operation in Indian waters. The ship has been nominated for an IMO ‘act of bravery’ award for its professional and daring rescue of a container carrier under fire in the Arabian Sea. ICGS Samudra Prahari is 95 metres long, draws 4,300 tonnes at max displacement and is propelled by 3,000 KW twin diesel engines whose power is further enhanced by twin shaft generators for a maximum speed of 21 knots. At economical speed, it has an endurance of 6,500 nautical miles and can stay at sea for 20 days.

The ship is equipped with state-of-the-art pollution response and control equipment that include containment equipment like Hi sprint booms and river booms, recovery devices like skimmers and side sweeping arms and storage devices like Oil Recovery Operation (ORO) tanks and inflatable barges.

The ship is capable of unhindered oil recovery operations with storage capability of 502 KL. The special features include an Integrated Platform Management System, Power Management System, High Power External Fire Fighting System and one indigenous CRN 91 Gun mount along with fire control system.

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3/22/2013 8:26:05 PM

Not Shortage, Unwillingness to Align Fuel Prices a Threat to Economy: Montek New Delhi: The Deputy Chairman of the Planning Commission Montek Singh Ahluwalia has expressed that it is not fuel shortage, but the unwillingness to align energy prices with market rates acting as a threat to the economy of the country.

He stated that we have not aligned petroleum prices. Diesel prices are low. Kerosene prices are much lower. The price of natural gas is one third.

Our domestic price (of gas) is USD 4.2 per million British thermal unit but imported gas is USD 13 per mmBtu.

The country subsidises diesel and cooking fuel and also controls rates for coal and natural gas that are lower than the market price.

He added that If we want to import coal, gas or petrol, it is freely available.

But the problem is that imported coal is 60 to 70 per cent more expensive.

Global Transformer Oil Market to Reach $2.46 billion Hallin Marine Commences Well-head Installation by 2017 Support Project off Mumbai New Delhi: Global transformer oil market is expected to grow from USD 1.59 billion in 2012 to USD 2.46 billion by 2017, with a CAGR of 9.17 per cent.

In this, mineral oil-based transformer oil is expected to occupy the major share, when compared to silicone and bio-based transformer oils for the next five years.

Asia-Pacific has been the largest transformer oil consumer since 2011 followed

by North America, Europe, and ROW. The major transformer oil consuming countries in Asia-Pacific are China, India, and Japan. The consumption is high in these countries mainly due to the increasing economic development, rising population owing to growing electricity demand. The trend is estimated to remain the same during the forecasted period. The consumption is high in the Asia-Pacific region, mainly due to the increasing economic development, population, and electricity demand.

Considering transformer oil consumption by types (Mineral oil-naphthenic & paraffinic, silicone, and bio-based), mineral oil constituted the largest consumption share as of year 2012 and is expected to be largest segment by 2017. Naphthenic oil constituted the largest share of mineral oil consumption in 2012.

Mumbai: Hallin Marine, a Superior Energy Services company, has announced the commencement of a saturation-diving and air-diving project off the coast of Mumbai, India. Working in partnership with Bumi Armada Berhad, Hallin provides a complete diving system plus full diving team and operating crew.

“Hallin started off as a diving company and is well known throughout the industry for its in-house design and build capabilities.” Explained Rik Zwinkels, Managing Director of Hallin East. “This project centres on the installation of three new wellhead platforms, D1-B, D1-C and D1-D. Output will be processed on board a floating production, storage and off-loading vessel located 2 kilometres southeast of the existing D1 platform which is 200 km to the west of Mumbai. The greater part of the saturation diving activity will be undertaken on a pipeline-end manifold structure located in 95 metres of sea water.

Additional saturation diving will be conducted at the D1-B platform and along the proposed power cable route, all at between 82 and 95 metres water depth.

The diving work scope will include J-tube protection cover removal, messengerwire connection to power cable, concrete mattress placement if required, tiein of flexible riser flange connections at the pipeline end manifold, subsea tie in and jumper connections, and post-installation surveys. The project is scheduled to complete by April 2013 with option to extend.

Essar Energy Receives Green Nod for Raniganj Phase III Development Kolkata: Essar Energy plc, the India-focused integrated energy company, has been granted phase III environmental clearance for its coal bed methane (CBM) gas field at Raniganj, West Bengal, allowing it to increase drilling to 650 wells.

The phase III approval was granted by the Government of India’s Ministry of Environment and Forests.

This environmental clearance allows the full field development of the Raniganj block, excluding forest area, and will enable Essar Energy to increase production to the targeted level of around 3 million standard cubic metres of gas per day (scmd), up from around 60,000 scmd currently.

So far, 135 wells have been drilled at Raniganj, of which 57 are in production.

The drilling programme will now be accelerated. Raniganj, in which Essar Energy has a 100 per cent interest, is a 500 km 2 block with total proven and probable reserves (2P), independently evaluated by consultants Netherland, www.oswindia.com

India News.indd 40

Sewell and Associates Inc, of 113 billion cubic feet (bcf ) gross (3.2 billion cubic metres), or 18.8 million barrels of oil equivalent. There are also best estimate contingent resources (2C) of 445 bcf gross, or 74.1 mmboe and 297 bcf gross, or 49mmboe, of current best estimate prospective resources.

Naresh Nayyar, CEO, Essar Energy, said that the final phase III environmental approval for Raniganj is an exciting milestone and is the key for the company to reach peak production.

Essar expects to grow the coal bed methane business significantly in the coming years as the company will utilise the learnings from Raniganj to develop other four blocks.

The company is awaiting a Government decision on an appropriate commercial sales price for Raniganj, but in the meantime will continue to sell gas from the block at the approved test sales price.

Offshore World | 40 | FEBRUARY - MARCH 2013

3/22/2013 8:26:06 PM

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news

Americas

Petrobras Confirms Extension of Fourth Well Find Gulfsands Petroleum Bags Exploration Contracts in Santos Basin in Colombia Brazil: Petrobras has confirmed the presence of good quality oil in well 3-RJS-706 (3-BRSA-1132-RJS), located in the Iara area, block BMS-11, in the Santos Basin pre-salt.

The find confirms the extension of of an earlier pre-salt discovery. The well is located 226 km off the coast of Rio de Janeiro, 6 km from the discovery well (1-RJS-656, Iara), at a water depth of 2,197 meters.

This well, the fourth in the Iara area, is still undergoing the drilling stage and will continue with the aim of defining the base of the oil reservoirs. Results have confirmed 28º API oil in good quality carbonate reservoirs, obtained by cable samples, starting at a depth of 5,260 meters.

The Consortium is going to proceed with the activities outlined in the evaluation plan approved by Brazil’s National Petroleum, Natural Gas and Biofuels Agency (ANP), which includes a formation test to assess the reservoir’s productivity.

Petrobras is the operator of the consortium with 65 per cent operated interest, in partnership with BG E&P Brasil holding 25 per cent and Petrogal Brasil/Galp Energia holding the remaining 10 per cent.

USA: Gulfsands Petroleum plc, the oil and gas production, exploration and development company, has bagged two exploration and production agreements with the Agencia Nacional de Hidrocarburos (ANH) in Colombia with respect to licence areas referred to as Llanos Area 50 and Putumayo Area 14 in the Llanos and Caguan Putumayo Basin respectively.

The signing of these agreements follows from preliminary awards made by the ANH in late 2012 upon the conclusion of the heavily subscribed Ronda 2012 bid round. While both of these licence areas are considered to be highly prospective for oil, the successful applications involved attractive financial terms and modest minimum exploration work obligations over the initial 4 year exploration terms.

The company has been recognised by the ANH as the qualified operator for these blocks and is currently finalising the constitution of a consortium to undertake exploration activities anticipated to commence in the next 12 months with 2D seismic programmes on both licence areas.

A further announcement on the conclusion of joint venture discussions and the proposed work programmes to be undertaken, will be made in due course.

Wison, EDF and Exmar to Build Barge-mounted Anadarko Enters Carried-interest Agreement for Heidelberg Development LNG Plant USA: Wison Offshore & Marine Ltd, EDF Trading and Exmar NV have agreed to collaborate to develop an offshore, barge-mounted LNG liquefaction facility for use in North America.

Wison would be responsible for the turnkey engineering, procurement, construction, installation, and commissioning (EPCIC) services for the mobile, self-contained units that would be capable of tying in to existing pipeline, tank and jetty infrastructure to enable LNG export. These plants will utilise topside liquefaction equipment and packages designed by Black & Veatch using its PRICO single mixed refrigerant technology.

Wison and Exmar cooperated to build the first-ever floating liquefaction, re-gasification, and storage unit which is scheduled to go onstream offshore Colombia in 4Q 2014.

Kvaerner Bags ExxonMobil’s EPC Contract Canada: ExxonMobil Canada Properties has released Kiewit-Kvaerner contractors to provide engineering, procurement, and construction services for the Hebron Project gravity based structure. The contract value is USD 1.5 billion and includes work done to date. Work will be done in Newfoundland and Labrador, Canada, with engineering in St. John’s and construction at the Bull Arm fabrication yard.

The completed GBS will be installed at the Hebron field on the Grand Banks in the Atlantic Ocean, 350 km (217.5 mi) offshore from St. John’s, Newfoundland and Labrador, Canada.

Mexico: Anadarko Petroleum Corp has signed a definitive agreement with an undisclosed party to enter into a carried-interest arrangement for a portion of Anadarko’s ownership in the Heidelberg development project in the deepwater Gulf of Mexico.

Under the terms of the agreement, Anadarko will be carried for USD 860 million, which represents nearly all its expected capital requirements through the anticipated date of first oil at Heidelberg in mid-2016. In exchange, Anadarko will convey a 12.75 per cent working interest in the Heidelberg development. Anadarko will continue as operator with a 31.5 per cent working interest.

The agreement is expected to close in April 2013, with an effective date of April 2013, and is subject to existing preferential rights, contingencies, and other customary closing conditions.

Al Walker, President and CEO, Anadarko, said that this agreement establishes a market value of approximately USD 3 billion for Anadarko’s interest in the Heidelberg deepwater development, which is estimated to hold up to 400 MMbbl of recoverable resources. The Heidelberg development is located in 5,300 ft (1,615 m) of water, about 140 mi (225 km) offshore Louisiana, and consists of Green Canyon blocks 859, 860, 903, 904, and 948. The project is being developed by utilising a truss spar, which is currently under construction, with a design capacity similar to the Lucius spar at 80,000 b/d.

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3/22/2013 8:33:26 PM

McDermott Bags Pemex’s GoM Platform Contract Mexico: McDermott International Inc has received a letter of award for a turnkey contract from PEMEX Exploracion y Produccion for the PB-Litoral-A production platform in the Litoral Tabasco Tsimin-Xux fields.

The USD 230-million project scope includes front-end engineering design, detailed engineering, procurement, fabrication, load-out, sea fastening, transport, installation, hook-up, commissioning and start-up of an eightlegged 1,800-metric tonne (1,984-tonne) jacket, 4,500-metric tonne (4,985-tonne) topsides and 2,000 tonne of tripods, bridges, and piles. The total weight of the facility is approximately 8,300 metric tonne (9.149 tonne).

McDermott will also provide training to PEMEX personnel for operation and maintenance of the facility once commissioned.

Engineering work is expected to begin early this year by McDermott’s Houston and Chennai engineering offices, with fabrication at Altamira, Mexico.

McDermott will carry out installation of the topsides by the float-over method using its Intermac 600float-over barge, and the recently upgraded and improved McDermott Derrick Barge 50 will install key platform components and provide additional support.

In addition to the PB-Litoral-A scope, McDermott International Inc will undertake bridge and piping tie in, as well brownfield work on the CA-Litoral-A HP compression platform.

Full project completion is expected in second quarter of 2015.

Karoon Strikes Oil in Offshore Brazil

Marubeni to Acquire Stake in Williams Partners’ Gulfstar FPS Project Mexico: Marubeni Corp has agreed to acquire 49 per cent interest in Williams Partners’ first Gulfstar FPS project.

Upon closing of the agreement, expected in 2Q 2013, Marubeni will fund USD 225 million in capex and follow with monthly capex representing the 49 per cent interest.

Gulfstar FPS is Williams Partners’ proprietary floating production system. The initial Gulfstar FPS, which has been under construction since late 2011, will support Hess Corp and Chevron, with production handling, export pipeline, oil and gas gathering, and gas processing services the Tubular Bells field development in deepwater eastern Gulf of Mexico.

The Gulfstar FPS will tie into Williams Partners’ wholly owned oil, gas gathering and processing systems in the eastern Gulf of Mexico. Williams Partners also expects the initial Gulfstar FPS to be capable of serving as a central host facility for other deepwater prospects in the area.

The initial Gulfstar FPS is expected to be placed into service in mid-2014. Williams Partners expects to develop additional Gulfstar FPS projects in the future.

Gulfstar FPS is expected to have an initial capacity of 60,000 b/d of oil, up to 200 MMcf/d of natural gas, and the capability to provide seawater injection.

The facility is a spar-based floating production system with a three-level topsides mated to a classic spar hull. This standard design was selected to reduce the time from discovery to first oil.

Brazil: Karoon Gas Australia has reported an oil discovery in the Kangaroo prospect offshore Brazil.

This Gulfstar FPS is the first spar-based floating production system with major components being built entirely in the US Gulf Coast area. Fabrication of the hull is taking place in Aransas Pass, Texas. The topsides fabrication will take place in Houma, Louisiana.

The Kangaroo-1 exploration well, drilled by the Blackford Dolphin semisubmersible to a depth of 3,049 m (10,003 ft), encountered a 25-m (82-ft) light oil column in Eocene-aged rocks. The discovery was 300 m (984 ft) down dip from the tap crest as shown on seismic maps, Karoon said.

The company expects a potential hydrocarbon column of about 350 m (1,148 ft) for the entire trap.

FoundOcean Completes Installation and Grouting for Saipem America

The Kangaroo prospect is in the Santos basin blocks S-M-1101 and S-M1165 in water depths of approximately 400 m (1,312 ft). Karoon was awarded 100 per cent operated interest the blocks, along with S-M-1102, S-M1037, and S-M-1166, in 2008. In September, 2012, the company reached an agreement to divest 35 per cent of its interest in blocks S-M-1101, S-M-1102, S-M-1037 and S-M-1165 to Pacific Rubiales, which also holds an option to acquire 35 per cent interest in S-M-1166.

The seabed a water depth of 750 m (2,460 ft) was dredged at around the damaged area of the pipeline. An ROV maneuvered the two steel half-shells of the clamp into position and pre-tightened the bolts. FoundOcean then connected the hose to the inlet valve on the clamp and delivered the grout using its deepwater grouting umbilical system. Due to the extra load, a fabric formwork was installed under the clamp to provide more support.

Karoon’s Santos basin exploration programme will continue with wells at the Emu/Cassowary and Bilby prospects. www.oswindia.com

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Mexico: FoundOcean has completed installation and grouting for a clamp repair on an 18-inch pipeline in the Gulf of Mexico under contract from Saipem America.

In total 28 metric tonnes (30.86 tonnes) of cement was used: 4 metric tonnes (4.4 tonnes) for the clamp and 24 metric tonnes (26.46 tonnes) for the fabric formwork.

The pipeline damage resulted from an anchor drag during bad weather.

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Africa Videocon, Anadarko to Sell Partial Stake in Mozambique Field Mozambique: Videocon Industries and US energy major Anadarko Petroleum Corp have put on auction their 20 per cent stake in a giant Mozambique gas field, while Videocon has put on offer all of its stake to cut its debt, Anadarko is offering a part of its shareholding.

ONGC Videsh Ltd, the overseas arm of the state explorer, and Oil India Ltd (OIL), GAIL and Indian Oil Corp (IOC) are together negotiating for the stake, which would raise USD 4.5 billion.

Anadarko is the operator with 36.5 per cent stake in Mozambique’s offshore Area 1, which may hold as much as 70 trillion cubic feet of gas resources.

Videocon and a unit of Bharat Petroleum Corp Ltd (BPCL) hold 10 per cent stake each in the block where Japan’s Mitsui & Co Ltd is the second, biggest stakeholder with a 20 per cent interest. Thai state oil company PTT

Exploration and Production PCL has an 8.5 per cent interest and Mozambique’s state-owned ENH 15 per cent.

The gas found in Offshore Area 1 is to be turned into liquefied natural gas (LNG) and shipped to markets like India. The plant in the Cabo Delgado province in northern Mozambique is scheduled to start operating in 2018 with a capacity of 20 million tonnes of LNG per year. The capacity will be split evenly between operators of Offshore Area 1 and Italian giant Eni, which is developing gas found in the neighbouring Offshore Area 4.

Two major natural gas discoveries have so far been made in Offshore Area 1 of Mozambique’s Rovuma Basin. The Prosperidade complex is estimated to hold between 17 and 30-plus Tcf of recoverable natural gas while separate and distinct Golfinho/ Atum complex is estimated to hold 15-35 Tcf of recoverable natural gas resources.

Africa Oil Temporarily Suspends Paipai-1 Well Exploration Kenya: Africa Oil Corp has temporarily suspended the Paipai-1 exploration well in Kenya for ongoing evaluation.

The well, located in the Marsabit County of Kenya Block 10A, was drilled to a total depth of 4,255 metres and successfully logged.

The well was drilled to evaluate a large structural closure of Cretaceous age in the Anza Basin.

Light hydrocarbon shows were encountered while drilling a 55 metre thick gross sandstone interval. This sandstone is overlain by a 200 metre thick Cretaceous source rock which forms an effective regional top seal and yielded oil and gas shows throughout the section while drilling.

Attempts to sample reservoir fluids were unsuccessful and the hydrocarbons encountered while drilling were not recovered to surface. It was not possible to test the well at this time due to the unavailability in country of testing equipment capable of handling the higher reservoir pressures encountered at this depth. The well has consequently been temporarily suspended pending further data evaluation.

After suspension operations have been concluded at Paipai, the rig will move to the South Lokichar Basin in Block 10BB and drill the Etuko prospect in the undrilled basin flank play. The move is expected to take 3 months.

Tullow has a 50 per cent operated interest in the Paipai-1 well, Block 10A, with Africa Oil holding 30 per cent and Afren holding the remaining 20 per cent.

Cameron Bags Subsea Systems Supply Contract Hess Strikes Deepwater Well Offshore Ghana for 7th Time in Nigeria Nigeria: Esso Exploration and Production Nigeria has awarded Cameron a contract to supply the subsea systems for the deepwater Erha North Phase 2 offshore Nigeria.

Ghana: Hess Corp has completed drilling its seventh consecutive successful exploratory well on the Deepwater Tano/Cape Three Points block offshore Ghana.

The contract includes 32 subsea wellheads that will tieback to the existing Erha FPSO, as well as 5 subsea production trees, 2 water injection trees, 3 manifolds, production and topsides controls, and associated equipment.

The Pecan North-1 well, 7 mi northeast of the Pecan-1 well, encountered approximately 40 ft of net oil pay in Turonian-aged reservoir.

The project is scheduled to go onstream in 2015 at a production rate of 50,000 b/d of oil.

Erha and Erha North projects are in water depths of between 1,000 and 1,200 m (3,280 and 3,936 ft) in the Gulf of Guinea, approximately 97 km (60 mi) offshore.

Operator ExxonMobil holds a 56.25 per cent interest, while Shell holds the remaining 43.75 per cent.

All seven of the wells were drilled by the Stena Drillmax drillship in water depths of 5,623 ft to 8,245 ft.

Hess plans to submit appraisal plans for the discoveries to the government for approval and has begun pre-development studies on the block.

Hess holds a 90 per cent working interest in the block and is the operator.

Ghana National Petroleum Corporation (GNPC) is a 10 per cent equity interest partner and is carried through to the production phase of the license.

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Eni Confirms More Gas Discovery at Mamba Complex Gasol Raises Funds for Benin LNG Project in Offshore Mozambique Benin: Gasol has drawn down USD 20 million from a new bond instrument to Mozambique: Eni has announced the new gas discovery at offshore Mozambique in the Mamba Complex of Area 4. The Coral 3 delineation well confirms Area 4 potential of 27 tcf exclusively within Area 4, said Eni. Coral 3 was drilled in 2,035 m (6,675 ft) of water and reached a TD of 5,270 m (17,286 ft). The well is approximately 5 km (3 mi) south of Coral 1, 15 km (9 mi) from Coral 2, and approximately 65 km (40 mi) off the Cabo Delgado coast.

The well encountered 117 m (384 ft) of gas pay in a high-quality Eocene reservoir and adds at least 4 tcf of gas in place to Area 4, said Eni. The discovery proved the existence of hydraulic communication with the same reservoir of Coral 1 and Coral 2, and confirms the size of the Coral discovery that is now estimated to contain 13 tcf plus of gas in place wholly in Area 4.

Eni plans to drill another delineation well, Mamba South 3, to assess the potential of the Mamba Complex discoveries before returning to exploration drilling in the southern sector of Area 4.

Eni is the operator of Area 4 with a 70 per cent participating interest. The other partners of the joint venture are Galp Energia (10 per cent), KOGAS (10 per cent), and ENH (10 per cent), carried through the exploration phase.

Simba Energy Finds Three Significant Oil Discoveries in Guinea Guinea: Simba Energy Inc, the pan-African oil & gas explorer, has found three additional and significant seeps during its initial phase of 2013 exploration work on Blocks 1 & 2 in the Republic of Guinea’s Bove Basin.

James W Dick, Director and CTO, Simba Energy, said that the company identified and confirmed a number of known seep areas within Block 2, these three additional seep areas (two in Block 1), from Paleozoic rocks, are impressive and clearly the best seeps seen to date, during the further site visit.

He added that these new findings will certainly increase the prospectively of both the blocks with the presence of higher C hydrocarbons. A number of samples have been sent to the lab for analysis.

In view of the results to date, the company now plans to focus its initial exploration work in the Republic of Guinea on Block 1 and the northern part of block 2.

The Company is planning a geochemical survey to collect 2,000 samples covering 1,000 line kilometers mostly within Block 1 to focus upcoming phases of exploration.

Crews will be mobilised within the next month with completion anticipated shortly thereafter. www.oswindia.com

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fund initial development work and studies for its LNG import project in Benin.

Alan Buxton, Chief Operating Officer, Gasol, said that securing the bond from institutional investors in a tight credit market was a very strong endorsement of its strategy.

The West African energy development company aims to line up gas supply to feed into the 678-kilometre West African Gas Pipeline to markets it sees as under-supplied in Benin, Togo and Ghana.

Gasol is aiming to develop gas markets in West Africa through LNG import projects prior to commercialising its own resources.

The USD 20 million draw-down is part of a multi-tranche, unsecured bond instrument worth up to USD 100 million, with a 10 per cent interest rate and maturity of three years.

Ghana Govt to Review TEN Offshore Project Development Offshore Ghana Ghana: Tullow Oil has estimated capex of USD 4.5 billion for the development of the TEN project offshore Ghana. The plan, currently under consideration by the Ghanaian Ministry of Energy, takes in the Tweneboa, Enyenra, and Ntomme (TEN) discoveries in the Deepwater Tano block.

The capex figure includes about 23 injection and production wells, but excludes lease costs for the FPSO. Bids have been submitted from two contractors for the FPSO, and Tullow expects a contract award soon, pending approval for the project. This will have production capacity of about 80,000 b/d, but with a flexible design that allows for future expansion via near-field tie-ins.

Subsea front-end engineering design has been completed and tenders are being evaluated. Tullow aims for start-up from TEN within 32-36 months of government sanction.

Statoil Strikes Gas Again Offshore Tanzania Tanzania: Statoil and partner ExxonMobil have discovered more gas in block 2 offshore Tanzania. The 4-6 tcf (113-170 bcm) in place in the Tangawizi-1 well lifts total volumes on the block to date to 15-17 tcf (425-481 bcm).

Tim Dodson, Executive Vice President for Exploration in Statoil, said that the company so far completed five wells and will continue with further wells later this year.

Tangawizi-1, drilled by the Ocean Rig Poseidon in 2,300 m (7,546 ft) water depth, encountered gas was in tertiary sandstone. The location is 10 km (6.2 mi) from the earlier Zafarani and Lavani finds.

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Russia & EU GE Wins Service Contract Extension of Sakhalin-2 LNG Plant Russia: GE Oil & Gas has received a 16-year service contract extension valued at USD 333 million for Sakhalin-2, one of the world’s largest integrated oil and gas projects that operates in the harsh subarctic environment of Sakhalin Island in the Russian Far East.

The service contract extension covers four GE Frame 7EA gas turbines that drive the process trains for Sakhalin’s liquefied natural gas (LNG) plant—the first of its kind in Russia—and five GE Frame 5 gas turbines that are used for electricity production at the site.

The agreement underscores GE’s commitment in local resources and a local workforce for the facility, which delivers economic benefits for both the Sakhalin region and all of Russia.

The extension to the Sakhalin Energy-GE contractual services agreement (CSA) for maintenance and services on Sakhalin Energy’s LNG plant gas turbines has been approved by Sakhalin Energy’s shareholders and Russian stakeholders. This adds two cycles to the existing CSA, will deliver more production availability and represents a significant commitment to the use of local content.

GE signed a memorandum of understanding (MoU) with the Sakhalin provincial government to work together in developing power generation projects to meet the future energy needs of Sakhalin Island.

The MoU covers a wide range of GE technology options, including aeroderivative gas turbines, gas engines, coal gasification and wind power.

The GE service agreement includes planned and unplanned outages, parts and repairs, an availability guarantee, remote monitoring and diagnostics and an on-site GE team of technicians. The agreement will be supported by GE’s technology and services center in the Kaluga region of Russia.

Statoil Awards Aasta Hansteen Subsea and Sparrows Secures £190 million Deals Marine Contracts UK: Aberdeen-based oil service company Sparrows Group has been awarded Norway: Statoil and its partners have awarded several subsea pipeline and marine installation contracts to Subsea 7 and Deep Ocean for the Aasta Hansteen field in the Norwegian Sea.

several major contracts totalling more than EUR 190 million.

The deals include 134 existing jobs on and offshore while 54 new positions have already been created with more expected to follow.

The contracts will provide ripple effects in Northern Norway. The total contract value is estimated at NOK 2.3 billion (USD 400 million), of which NOK 2.2 billion (USD 383 milion) has been awarded to Subsea 7 and NOK 165 million (USD 28 million) to Deep Ocean.

The contracts are with Shell, CNR, ConocoPhillips, Perenco and Wood Group in the North Sea. Sparrows has also signed or renewed agreements to work with BP in Angola and CNR in Gabon and Cote d’Ivoire.

The Aasta Hansteen field development represents a number of firsts on the Norwegian Continental Shelf (NCS) in terms of water depth and technological solutions. As part of the contract, both companies plan to use local suppliers in northern Norway.

The European and African contracts, worth a combined EUR 150 million, will be managed from Sparrows operating base in Aberdeen. The company has also won orders and contracts worth an additional EUR 40 million in the USA, Middle East and Asia.

This work will be performed by Subsea 7 who has been awarded contracts worth an estimated NOK 2.2 billion for the subsea lines and marine operations including floating production storage and offloading (FPSO) unit tow to field and mooring.

These new contract wins for 2013 follow excellent provisional results for 2012. Like-for-like revenues were up 10 per cent on 2011 and earnings on these continuing operations were up 19 per cent in the same period, with the increased profitability coming largely from efficiencies and from growth in overseas activities.

This includes amongst others the engineering, procurement, commissioning and installations (EPCI) of flowlines and steel catenary risers, and procurement of line pipe for the flowline part of the EPCI contract.

Subsea 7 is planning to establish a permanent presence in Northern Norway due to this contract award. They also plan to utilise local suppliers from Northern Norway. The complex pipeline production activity for the steel catenary risers and flowlines will take place at Subsea 7’s spoolbase at Vigra, Norway.

Deep Ocean will supply and install the 140 km fibre-optic cable to connect the Aasta Hansteen field to the existing infrastructure near Norne.

The largest single win is the renewal of a contract to deliver crane and lifting services on all Shell installations in the UK and Dutch sectors of the North Sea. The five-year contract will have the option of two one-year extensions and means Sparrows continues its unbroken service record to Shell installations since 1976.

The contract to provide crane operation and maintenance services across CNR’s five platforms in the North Sea requires Sparrows to deliver a full resident offshore crane operation and maintenance service, including onshore engineering support, to the first platforms just four weeks after the initial signing with crews on all five platforms to be up and running just ten days later.

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Repsol to Start Gas Production from SK Field Russia: Repsol and its partner Alliance Oil have begun commercial gas production from the Syskonsyninskoye (SK) field in the Khanty-Mansiysk region of Russia. Repsol confirms the production start-up marks the first success of the A&R Oil and Gas (AROG) joint venture that the two companies established to explore and produce for hydrocarbons in Russia.

The company expects six more wells to be drilled on five locations by early 2014 as the joint venture further develops the field during the coming year.

The initial gas production amounted to 5,350 barrels of oil equivalent per day (boepd) and that the gas is being delivered to the Gazprom transportation network. To date, five production wells have been drilled and three of these have been put into operation.

Fernando Martinez Fresneda, General Manager, Repsol, said that the first successful start-up through AROG proves the great potential the oil block which will continue to supply large volumes of gas to the domestic market in coming years.

AROG’s total output now stands at 25,000 boepd, while its proven and probable reserves amount to 218 million barrels of oil equivalent.

More Wells in Prospect on Deepwater Permit SolveiG Intends to Join Norway Pipeline Group Offshore Egypt Norway: Statoil is selling a 24.1 per cent direct and indirect stake in the Egypt: Statoil BG Group has sanctioned a next phase of development for the West Delta Deep Marine (WDDM) concession in the Egyptian sector of the Mediterranean Sea.

Gassled pipelines joint venture to SolveiG Gas Norway for NOK 17.35 billion (USD 3.2 billion).

Pending approval from partner Petronas will come onstream in 2014, said BG CEO Chris Finlayson.

Gassled owns the gas transportation grid and processing facilities on the Norwegian continental shelf (NCS), taking gas from Norway’s fields through a network of long-distance offshore trunklines to consumers on the European mainland and in the UK.

BG CEO Chris Finlayson

Since 1994, BG Group has discovered 14 gas fields in the concession.

Produced gas heads to Egypt’s domestic market, Egyptian LNG at Idku, and the Damietta LNG plant.

The sale will reduce Statoil’s share in Gassled to 5 per cent.

It was formed in 2003 via the merger of most of Norway’s existing gas pipeline joint ventures into one organization, and today provides transportation services with third party access to producers on the NCS.

In 2010 BG started work on the Phase 7 facilities, comprising a new 68km (42 mi), 36-in. offshore pipeline and associated onshore gas reception facilities, a slug-catcher adjacent to the two existing WDDM pipelines, and five new compressors. Flow through the new pipeline started in 2011, with the compression plant becoming operational in January 2012.

SolveiG is a holding company owned 45 per cent by Canada Pension Plan Investment Board; 30 per cent by Allianz Capital Partners, a subsidiary of Allianz SE; and 25 per cent by Infinity Investments, a subsidiary of the Abu Dhabi Investment Authority.

Last June, gas production from the Phase 8b deepwater development project came onstream. This is an extension of the existing deepwater subsea infrastructure and involved tying in eight subsea wells. Once completed, WDDM is due to have 51 subsea wells in service.

Statoil said that scaling back its presence in Gassled will allow it to redirect capital into assets and projects yielding higher rates of return. But the company remains committed to the development and supply of Norwegian gas and will continue to be the largest shipper in Gassled.

According to BG, Phase 9 is next in line, taking in additional infill wells, new development wells, and further workovers.

The transaction is subject to approval from the Norwegian Ministry of Petroleum and Energy and the Norwegian Ministry of Finance.

Bowleven Testing Pay Zones in Well Offshore Cameroon UK: Bowleven Oil & Gas has found hydrocarbon-bearing pay while drilling the IM-5 well in block MLHP-7 offshore Cameroon in 56 m (184 ft) water depth.

The well, on the Etinde permit, recorded hydrocarbons in both the Middle Isongo and Intra Isongo objectives based on core analysis, wireline logs, fluid www.oswindia.com

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samples, and pressure data. The well has reached targeted TD of 3,430 m (11,250 ft) measured depth and is setting liner for further testing.

Bowleven has reported the Middle Isongo interval to have 25 m (82 ft) net pay at a MD of 3,360 m (11,021 ft). The Intra Isongo sand is reported to have 70 m (230 ft) of net pay.

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South East Asia Gazprom and CNPC Agree to Sign Supply Deal China: Gazprom and China National Petroleum Corporation (CNPC) have agreed to sign a gas purchase and sale contract on Russian natural gas supply via the eastern route till 2013.

This deadline was set according to the decision of the Russian-Chinese Intergovernmental Commission on Energy Cooperation headed by Arkady Dvorkovich, Deputy Prime Minister of the Russian Federation and Wang Qishan, Vice Premier of the State Council of the People’s Republic of China.

The parties confirmed the previously arranged basic parameters of Russian gas export to China, including the volume of delivered gas, the starting date of supplies and their duration, gas delivery point on the border and other conditions. In the nearest future the negotiations will be continued on the expert level to reach agreements on other supply terms as soon as possible.

In addition, the parties paid attention to LNG cooperation outlooks, primarily, to the potential interaction within the Vladivostok-LNG project.

Ezra to Divest Stake in Lewek Arunothai FPSO

Songa Venus Secures Extension Contract

Malaysia: Ezra EOC plans to sell 51 per cent interest in the entities owning and operating the floating production storage and offloading Lewek Arunothai.

Malaysia: Songa Offshore SE, the Norwegian-Cypriot offshore drilling contractor, has entered into a contract extension and farm out agreement with Mubadala Petroleum from the semisubmersible drilling rig Songa Venus’ current contract with Petronas.

Lewek Arunothai has been chartered by Hess Exploration and Production Malaysia for three years, with an option to further extend three years.

Under the agreement, Ezra EOC has entered into a share sale and purchase agreement with Perisai Petroleum Teknologi BHD for the sale of 51 per cent of the equity interest in the entities owning and operating the FPSO and the purchase 50 per cent of the equity interest in SJR Marine.

The extension will cover a total of four firm wells in Vietnam and Malaysia under the current contract terms and conditions. This extension will see the unit occupied until October 2013.

The extension has an aggregated revenue value of approximately USD 21 million.

Myanmar to Seek Bid for Offshore Oil & Gas Blocks Myanmar: Myanmar plans to launch a long-awaited bidding round for 30 offshore oil and gas blocks in April this year, which is likely to attract participation from international oil majors.

The auction of exploration rights will be another step to attract foreign investment and expertise to help overcome an energy deficit of the country.

The government of the impoverished and isolated Southeast Asian country is now seeking billions of dollars in investments to tap the oil and gas reserves believed to lie in largely-unexplored offshore areas.

Myanmar produces more than enough natural gas, which is its primary source of energy after biomass, to meet domestic needs. But it exports about

80 per cent of the 1.2 to 1.4 billion cubic feet of gas it produces each day to Thailand.

Myanmar needs about half of the natural gas it needs to meet domestic demand. If it didn’t export so much, it could easily meet its domestic needs, which are expected to rise from 471 million cubic feet per day in the fiscal year that ends March 31 to 918 million cubic feet per day next fiscal year.

The government had initially planned to put the blocks on offer last year, but the bidding round was postponed amid concerns from foreign investors over transparency in the industry. The government has pledged to strictly follow international standards in the bidding process.

PTTEPI Divests its Operating Interest to Mitsui in Myanmar Myanmar: PTTEP International Ltd, a wholly-owned subsidiary of PTT Exploration and Production Public Company Limited, has agreed to divest 20 per cent of its operating interest in block M-3 offshore Myanmar to Mitsui Oil Exploration Co Ltd. The Block M-3 is located in a geologically high potential area close to the Yadana gas field, one of the major gas fields discovered in offshore Myanmar.

The M-3 covers 6,206 sq km (2,396 sq mi) in the Gulf of Martaban.

PTTEPI is the operator and had held 100 per cent of the interests. The transaction is subject to official approval by the Republic of the Union of Myanmar.

In 2011, an exploratory well was drilled in Block M-3 which resulted in the discovery of natural gas.

Mitsui has positioned Myanmar and other targeted parts of South East Asia as its core business area

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Salamander Energy Begins Oil Production in Thailand Thailand: Salamander Energy, the Asian oil and gas E&P company, has started oil production first four wells of the sixteen-well development drilling programme through the Bualuang Bravo platform in the Gulf of Thailand.

Salamander has a two year contract with the Atwood Mako rig, until September 2014.

The jackup Atwod Mako drilled and completed the horizontal BB-04H development well from the platform on the Bualuang field. After clean-up operations, the well should produce at its planned rate of 1,500 b/d.

The Bualuang field is presently producing more than 8,300 b/d. As the development program progresses, with 15 more wells to be added, next year output is expected to increase to 11,000-14,000 b/d.

Kreuz Wins Two Subsea Installation Contracts

Swiber Bags Contracts Southeast Asia

Singapore: Singapore’s Kreuz Holdings Limited, an integrated subsea service provider for the oil and gas industry, announced that it has been the recipient of subsea installation contract awards worth USD 15.5 million for projects in Southeast Asia.

The rig is currently drilling the second development well from the platform BB-10H.

for

Execution

in

The USD 10.0 million project is scheduled for immediate commencement with completion in the first quarter of 2013, while the USD 5.0 million contracts are slated for commencement in the second or third quarter of 2013 with completion in the third quarter of 2013.

Singapore: Swiber Holdings Limited, a world class integrated construction and support services provider to the offshore industry, announced that it has been awarded contracts worth approximately USD 153 million. The contracts, which mark the first wins for the company in 2013, largely entail transportation and installation of pipelines and offshore Francis Wong, Group CEO and structures in Southeast Asia. Work for President of Swiber these contracts is expected to commence immediately with expected completion by 2013.

Kurush Contractor, Executive Director and CEO of Kreuz commented, “These positive wins are our first in this new year of 2013, and reflects Kreuz’s favourable standing in the oil and gas industry. Kreuz will continue to seek opportunities in winning new work to increase the Group’s order book, establish new relationships, and enhance our track record and utilisation of assets.”

Francis Wong, Group CEO and President of Swiber, said that over the years, Swiber has established a proven track record in executing challenging offshore construction projects that require precise execution and timely delivery. Swiber continues to raise this torch high, winning these contracts worth USD 153 million from existing and new clients.

This comprises a USD10.0 million project from a third party client, a leading offshore customer, and USD 5.5 million contracts from the Swiber Group.

Petrovietnam, Eni Pen Pact for Unconventional Energy Exploration Vietnam: State-backed PetroVietnam and Italian major Eni SpA have inked a joint venture agreement to pave the way for the latter to enter into partnerships for coal bed methane and shale oil exploration projects in Vietnam.

As per the agreement, studies to ascertain Vietnam’s unconventional hydrocarbon potential will be carried out by a mixed PetroVietnam-Eni team.

As per the latest agreement between the two companies, PetroVietnam acquires shares in international areas and blocks where Eni owns the rights to exploration and development.

tests over an area of 309 square miles (800 square kilometers) and drill an exploration well. For block 120, the Italian major will conduct seismic tests over an area of 97 square miles (250 square kilometers) and drill an exploration well.

Block 105 covers 2,777 square miles (7,192 square kilometers) in water depths of 66 feet to 262 feet (20 meters to 80 meters) over the Song Hong Basin offshore north central Vietnam. Oil and gas consultancy Netherland Sewell & Associates estimates that the block could contain around 461 million barrels to 1,724 million barrels of proven oil reserves.

Eni, which has been awarded rights to participate in offshore blocks 114,120 and 105-110/04, will start exploratory drilling works in June. Eni gained access into blocks 105-110/04 and 120 when it purchased 25-percent stakes of the blocks from Neon Energy and KrisEnergy in June of last year.

Block 120 covers 3,270 square miles (8,469 square kilometers) in the northern Phu Khanh Basin, offshore central Vietnam, where water depths range from 164 feet to 3,609 feet (50 meters to 1,100 meters).

Neon Energy and KrisEnergy detailed Eni’s development plans for both of the blocks in a disclosure last year. For block 105, Eni plans to conduct seismic

Netherland Sewell & Associates projects that the block could house 4 trillion cubic feet (Tcf ) to 14 Tcf of proven gas reserves.

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Middle East Dana Gas Commences Production of Oil Discoveries in Egypt UAE: Dana Gas PJSC, the Middle East’s first and largest regional private sector natural gas company, has commenced commercial production from the West Sama-1 and Allium-1 fields in Egypt, less than 2 months after initial well testing was conducted.

Rashid Al Jarwan, Executive Director and Acting CEO of Dana Gas said: “We are pleased to announce the successful tie-in of these two discoveries. The wells increase our production by 20 million cubic feet per day, providing much needed additional production to the Egyptian market and maintaining vital supplies of gas for power generation.”

These new fields are among the three discoveries made by Dana Gas in Egypt’s Nile Delta Basin during the Company’s 2012 multi-

well drilling programme.

Dr Patrick Allman-Ward, Dana Gas Egypt General Manager commented: “Dana Gas is well positioned to bring new discoveries on stream due to the onshore location of our assets where tie-ins to our existing pipelines and processing infrastructure can be made quickly, relatively inexpensively and ensures a high return on our new gas discoveries.”

Dana Gas plans to bring the other field, Balsam-1, into production in H2 2013. Gas production at West Sama-1 and Allium-1 has been routed through Dana Gas’ South El Manzala and El Wastani gas plant respectively.

Production from the two wells is expected to add 3,450 barrels of oil equivalent per day (boepd) (20 MMcf/d) to the Company’s 2012 Egypt year-end output rate of 32,000 boepd.

Rashid A l Jar wan, Executive Director and Acting CEO of Dana Gas

Tethys Oil Completes Testing of B4EW4 Well Gazprom and Kurdistan Introspect Prospects in Exploration in Oman Oil & Gas Sector Oman: Tethys Oil has completed testing of the exploration well B4EW4 on Block 4 onshore the Sultanate of Oman. The well flowed at a combined rate of close to 3,000 bopd on a 36/64 inch choke from the Buah and Khufai sections. The well has been completed as a production well and will be put on a long term production test.

Rashid A l Jar wan, Executive Director and Acting CEO of Dana Gas

Magnus Nordin, Managing Director, Tethys Oil, said that the company is delighted with the results of this exploration well, and is looking forward to gain more data on this new discovery from the long term production test. The ongoing 3D seismic survey on the block has been extended to also cover the B4EW4 structure.

The B4EW4 well was spudded in November 2012 and was drilled to a final total depth of 3,030 metres. The well was drilled on a dense grid of high quality 2D seismic data approximately 20 km west of the Saiwan East oil field. Strong oil shows were recorded during drilling in the Lower Al Bashir, Buah, Khufai and Masirah Bay formations. The testing programme was designed to evaluate the Khufai and Buah reservoirs.

Kurdistan: Kurdish government officials have been discussing gas supplies with Gazprom, the Russian state company, in Moscow. Massoud Barzani, President of the Kurdistan Regional Government, met Gazprom CEO Alexei Miller.Barzani’s visit was to discuss prospects for oil and gas cooperation.

According to Gazprom, the discussion was about the prospects for bilateral cooperation deepening in the oil and gas sector. In particular, the meeting addressed potential interaction between Gazprom and Kurdistan’s oil and gas companies in geological exploration, development and operation of oil and gas fields.

Gazprom Neft, the energy giant’s oil subsidiary, is working on exploration blocks in the Kurdish region in northern Iraq. Reuters says new deals were been signed during Barzani’s visit to Russia.

However the ongoing dispute between Kurdish leaders and the government of Iran, which regards the regional government as illegal, create diplomatic and security difficulties.

The Kurdish government in December said production from the semiautonomous region could add at least USD 8 billion to Iraqi coffers. It has halted production in the past, however, because of political disputes with Baghdad.

Iran Confirms South Pars 19 Pipelay Completion Iran: Iran has confirmed the offshore installation of the second South Pars Phase 19 sour gas 32-inch pipeline in Persian Gulf. This will take gas from the Phase 19 platforms to an onshore processing terminal in Iran.

Work on the first sour gas transfer 32-inch line and associated glycol 4-inch line was completed this past October. In total, 231 km (143 mi) of pipelines were laid.

As for the ongoing South Pars 17 and 18 projects, drilling of the first seven wells is complete at the A18 platform.

Hassan Boyeri, Director for development of both phases, said that the first part of offshore drilling operations in this project was completed successfully after conducting final tests. The seven drilled wells have a gas production capacity of 15 MMcm/d (550 MMcf/d).

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Australia/NZ Jacobs Bags Contract from Shell in Australia Australia: Jacobs Engineering Group Inc, a construction services provider, has been selected by the Shell Company of Australia Ltd, a subsidiary of Royal Dutch Shell, for its Clyde Terminal Conversion Project in Sydney, Australia.

Under the terms of the contract, Jacobs is initially providing a Basic Design and Engineering Package (BDEP) to convert the Clyde Refinery and associated satellite Gore Bay Terminal into a competitive product import terminal.

Subject to subsequent approval, Jacobs is also expected to provide Engineering, Procurement and Construction Management (EPCm) services in the delivery phase of the project. The work is being performed from Jacobs’ Australian operations in Melbourne and Sydney.

Jacobs Group Vice President Tom Quinn stated that the company is delighted to bring thier local and global terminal experience to this critical project.

This contract continues thier relationship with Shell in Australia, where Jacobs successfully implemented clean fuels upgrades at Shell’s Geelong and Clyde refineries.

The Clyde Terminal Conversion Project involves extensive upgrades, refurbishment and re-use of the existing crude and product tankage that supplies truck loading and pipeline operations helping to service Sydney airport and Shell’s distribution of fuels into the New South Wales market from Parramatta Terminal.

Tap Oil Reports Gas Reserves in Tallaganda offshore Western Australia Australia: Tap Oil Ltd has confirmed the gross volumetric recoverable gas reserves to be 500 bcf in the WA-351-P part of the Tallaganda structure offshore Western Australia after a review of a preliminary assessment. This includes 222 bcf of P50 contingent and 278 bcf of P50 prospective resources. Tallaganda-1 was drilled in second quarter of 2012 and confirmed a gas discovery in the Triassic Mungaroo Troy Hayden, Managing Director formation of the Tallaganda structure within and CEO, Tap Oil WA-351-P. The structure straddles the adjacent WA-335-P permit to the south.

A comprehensive suite of wire line logs, including formation image logs, a wire line pressure survey and formation fluid sampling program were acquired in the well.

The southern portion of the Tallaganda structure that extends into WA-335-P has not yet been drilled. The geological assessment of the Tallaganda discovery and remaining block potential is continuing and there are no current plans to drill in WA-351-P this year. Both WA-351-P and WA-335-P are operated by BHP Billiton Petroleum Pty Ltd. Troy Hayden, Managing Director and CEO, Tap Oil, said that the company believes that there are a number of other prospects on-block within the Triassic Mungaroo formation that could be considered for further drilling to aggregate additional gas volumes.

TDW Completes Pressure Isolation Operations Offshore Australia

He added that additional leads and prospects have also been identified in the Jurassic and Early Cretaceous section.

Australia: Norway-based TDW Offshore Services has completed two pipeline interventions offshore Australia by using its SmartPlug pressure isolation technology.

AWE to Drill Two Additional Offshore Wells

The first intervention was carried out to protect a live gas infield flowline from falling objects. To limit the negative consequences that could flow from a dropped object, TDW isolated the operating facility from the surrounding impact zone. It was the first time the company used its SmartPlug system to mitigate the risk of damage to a pipeline during a construction operation.

TDW isolated the pressure in a 30-inch subsea flowline. First, a dual-module SmartPlug isolation tool was launched from the platform and pigged to the set location, and set. The pressure was then bled off from that point back to the platform. For the next six months, the SmartPlug tool remained in the line while construction activities took place. During this period, the company used its remotely-operated SmartTrack tracking and pressure-monitoring system to continuously monitor the location of the SmartPlug tool and pressure in the line.

The second pipeline intervention took place on a section of a 40-inch gas export pipeline (trunkline) that extends from an offshore platform to an onshore terminal. The intervention was required to complete a hydrotest on a 40-inch trunkline terminal refurbishment project involving multiple valve replacements. www.oswindia.com

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New Zealand: AWE Ltd, an Australian based oil and gas exploration and production company, announced that the PMP 38158 (Tui) Joint Venture has approved two more oil wells – Pateke-4H infill development well and Oi exploration well – in offshore New Zealand in the second half of 2013.

AWE, as the Operator, has entered into an agreement to secure the recently overhauled and upgraded Kan Tan 4 semi-submersible rig, operated by Frigstad Offshore, to drill both wells as part of a larger drilling campaign to be undertaken by other companies in New Zealand during 2013-14.

The Pateke-4H infill development well will target a mapped northern extension of the Pateke Field (part of the Tui field group) that is not being accessed by the current producing well, Pateke-3H. The well is planned to be drilled to a total measured depth of approximately 6,900m and will include a 2,500m horizontal section.

AWE estimates that Pateke-4H could increase field recovery by 2.3 million barrels (gross). AWE has previously booked its equity share of a Contingent Resource (2C) recoverable volume of 2.0 million barrels associated with this opportunity.

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products

GAS DETECTORS IN HAZARDOUS AREAS Crowcon’s Vortex FP Compact is designed to monitor toxic and flammable gas detectors or fire detectors where there is a need for the control system to be installed in Atex Zone 1 and 2 hazardous areas. It is particularly suited to confined spaces such as analyser shelters in refineries, offshore rigs or FPSO (Floating Production, Storage and Offloading) installations. The standard Vortex FP contains up to 24 relays and can monitor up to 12 gas/fire detectors, while the FP Compact contains up to 16 relays and can also monitor up to 12 detectors. Rated IP66 for dust and water ingress, both models meet all the latest gas detection legislation and EMC standards and is validated to the IEC 61508 (SIL 1) functional safety standard.

For details contact: Detection Instruments Pvt Ltd Plot El-36, Electronics Zone, TTC Indl Area, MIDCl, Mahape, Navi Mumbai 400 710 Tel: 022-27617663, 27617664, Fax: 91-022-27612103 E-mail: general@detection-india.com / sales@detection-india.com

PORTABLE VALVE ACTUATOR The EasiDrive portable valve actuator from Smith Flow Control securely and effectively operates valves in oil refineries, power plants, paper mills and chemical processing facilities, even where adverse climates, such as arid and dry-desert environments, make operations more challenging.

The tool is especially effective on valves that require a high number of turns or are otherwise difficult to operate because of high torque or where harsh environments make operations more difficult.

EasiDrive is a lightweight, portable and adaptable pneumatic tool. The tool’s custom engineered reaction device protects the user from the “kick” normally associated with other torque tools, eliminating the possibility of any injury associated with its operation.

EasiDrive also features a variable output torque, controlled by a choice of limited pre-set Filter Regulator (FRL) packs, which prevents excessive torque being applied and ensures proper and safe operation of the valve.

For details contact: Halma Trading and Services India Pvt Ltd B1-401 Boomerang, Chandivali, Andheri (E), Mumbai 400072 Tel: 022-67080400, Fax: 91-022-67080405 E-mail: V.Lakshmanan@smithflowcontrol.com

GAS DETECTOR FOR MONITORING OF COMBUSTIBLE GASES AND VAPOURS The Dräger PEX 3000 is a gas detector for continuous monitoring of combustible gases and vapours at concentrations below the lower explosive limit. Its new double detector sensor responds to gas up to three times faster than its predecessor. Its measuring signal is stable and resistant to poisoning. The integral DD type sensor is based on the proven catalytic bead detection principle. With its innovative gas inlet opening, the sensor is able to respond to gas in a matter of seconds. This allows users to immediately initiate countermeasures and prevent the formation of flammable atmospheres. The larger version is equipped with cable glands on the side, with mounting from below also as an option. If the transmitter and the sensor are to be positioned differently, the remote version is used. Instead of the sensor, it contains a second cable gland for connecting a remote Polytron SE Ex sensing head.

The PEX 3000 is approved according to the EU Directive 94/9/EC for use in temp between -40 and +65°C, and also in potentially explosive gas and dust atmospheres (zones 1, 2, 21 and 22).

For details contact: Draeger Safety (India) Pvt Ltd 3C-Goldline Business Centre, Linkway Indl Este, Malad (W), Mumbai 400 064 Tel: 022-28759977, Fax: 91-022-28759900 E-mail: safetyindia@draeger.com

MEMBRANE ELEMENT TO IMPROVE NATURAL GAS PROCESSING CAPACITY Honeywell’s UOP Separex Flux+ is a drop-in replacement for the membrane elements in existing Separex membrane systems. Separex Flux+ increases the removal of contaminants, such as acid gas and water, which must be removed before natural gas can be transported by pipeline for commercial use. In addition, the membrane element removes more CO2 per unit membrane area than existing membrane products. This helps debottleneck downstream processing units. Separex membranes eliminate the need for solvents, making the technology particularly desirable in remote locations where logistics make supply transportation to the site difficult. Because Separex membrane elements are inert solids, these membranes offer a spillfree, ecosystem-friendly solution. Honeywell’s UOP recently rebranded its existing Separex Cellulose Acetate (CA) membrane elements under the new name Separex Flux.

For details contact: UOP India Pvt Ltd / UOP Asia Ltd Tower B, Bldg 9, DLF Cyber City, DLF City Ph III, Gurgaon, Haryana 122 002 Tel: 0124-4031361, 403136, Fax: 91-0124-4031369, 4031370

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LPG GAS METERS

LPG DISPENSERS Oil & Gas Plant Engineers India Pvt Ltd offers special LPG dispensers procured from their Principals, Fluussigas Anlagen GmbH, Germany (FAS). These dispensers are approved by Explosives Deptt. as well as Weights & Measures. The range of products includes both single and double hose dispensers.

R R Sales Corpn offers a wide array of LPG gas meters procured from reputed vendors of the industry. These products are manufactured so as to cater to the wide ranging demands of the customers. The entire assortment is offered in various technical specifications so as to offer accurate measurement results.

For details contact: R R Sales Corpn A-266 Gr Flr, Bunkar Colony Ashok Vihar, Phase-4, New Delhi 110 052 Tel: 011-27303251 Fax: 91-011-27303251

A typical dispenser is complete with very reliable and accurate piston meter, vapour eliminator, valves, pressure gauges, high pressure dispensing hose, LPG nozzles, safety relive valves, diaphragm type accumulator and differential Valve etc. The design is also very aesthetic and with hydraulic side and electronics side separate compartment. The unit includes all required safeties and has inbuilt protection against network failure with electronic totalizator including temp compensation.

LPG AUTOMATIC VALVE Delta Industries offers a wide range of LPG automatic valve, which are known for its low maintenance feature.

The offered product is fully automatic, which is offered in two different models as per the application required. Delta Industries offer this valve at the most

For details contact: Oil & Gas Plant Engineers India Pvt Ltd No: 108-109, Chiranjiv Tower43, Nehru Place New Delhi 110 019 Tel: 011-26447007, 26427233, 26482594 Fax: 91-011-26482593

affordable price.

LPG CYLINDER PRESSURE REGULATORS

For details contact: Delta Industries H No: 166, Barwala Village, Delhi 110 039 E-mail: deltaindustriess@gmail.com

GAS SHUT-OFF VALVE Gas Secura is a device with advanced safety features, used for domestic liquefied petroleum gas (LPG) cylinders. It has a high pressure control sensor with a safety valve and a pressure gauge. Gas Secura provides unique solution on gas leakage. Gas Secura saves up to 20 per cent of gas.

In case of major leakage there is an auto shut-off valve.

For details contact: Nandini Marketings Pvt Ltd 306, Balaji Corporate, 19/1, New Palasia, Above ICICI Bank Indore, Madhya Pradesh 452 001 Tel: 0731-4038101; Fax: 91-0731-2531101 E-mail: nandinimarketings@gmail.com / priyanka.nmpl@gmail.com www.oswindia.com

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TYPHOON brand regulators for BMCG/ LPG come with pressure gauges. These single stage regulators are durable and ensure accurate control of gas with minimum outlet pressure fluctuations and comparatively high gas flow rates. TYPHOON regulators are a product of MESSER German technology.

These are durable and practical in construction meeting high operational demands in welding, brazing, heating, cutting, gouging, etc, and assets are highly versatile. These reliable and high performance regulators come at affordable prices.

For details contact: V N Associates No: 39, Sakthi Green Land, Phase 2, Vellakkinar Road G N Mills Post, Coimbatore Tamil Nadu 641 029 Tel: 0422-3294330, 2909148 Fax: 91-0422-2909148

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products

GAS FLOW METER

LPG VAPORIZER Metallizing Equipment Co Pvt Ltd offers high quality LPG vaporizer. It is attached to the system to convert the liquefied fuel into vaporized state to get the precise combustion process.

In this system the temperature can be adjusted according to the process requirements and it leads to the accurate melting of particles.

For details contact: Metallizing Equipment Co Pvt Ltd E-101, M I A, 2 nd Phase, Basni, Jodhpur, Rajasthan 342 001 Tel: 0291-2747601

INSERTION MASS FLOW METER Prism Instrumentation (I) Pvt Ltd’s Steel-Mass Model 640S, inserts easily into ducts and pipes up to 72-inches in size to accurately monitor total gas mass flow rate.

Larger probe lengths are available upon request. Typical applications are for general industrial process control include compressed air flow, aeration basin air flow, combustion air flow, natural gas fuel flow, custody transfer and stack gas emissions flow monitoring. The Model 640S also features a high temperature option (750 degrees F) and a self-cleaning purge option for dirty flow environments.

The Model 640S is offered with a wide range of process connections (including hot tap). For very large ducts, multi-point flow averaging arrays are available, complete with a self-contained human-machine interface (HMI) panel that allows for touch-screen field programming and operation of the entire system.

This meter features Sierra’s well known Smart Electronics Package for fieldrangeability, field flow-range adjustment, and field validation and diagnostics.

The Model 640S has very low pressure drop, and wide turndown. The Steel-Mass Model 640S is hazardous area approved by CSA and CRN (Canada), FM (USA), ATEX, CE and PED (EU), IEC Ex (Australia), GOST R (Russian Federation) and Chinese Pattern Approval (China). Meter accuracy is +/-1% of reading plus +/0.5% of full scale with repeatability of +/- 0.2% of full scale.

For details contact: Prism Instrumentation (I) Pvt Ltd Chetas House, Plot No: 1, Survey No: 89 Shree Siddhatek Society, Nr Pashan Lake, Sutarwadi Pune, Maharashtra 411 021 Tel: 020-25871111, 25870370

Kelvin Gas Technologies Pvt Ltd offers a positive displacement diaphragm gas meter with a standalone twin chamber unit. The twin chambers are each fitted with a flexible and gas-tight diaphragm which is moved by the differential between the inlet and the outlet pressure. Gas enters one side of the diaphragm pan while on the other side it comes out through the separate port on the valve. When one side is full, the rotating mono valve moves on to the next position, allowing the gas to fill the empty side. It is used for measurement of gas at low pressure for domestic and commercial application.

For details contact: Kelvin Gas Technologies Pvt Ltd Office No: 18, 1 st Flr, Mahavir Center Plot No: 77, Sector 17 Above Golden Punjab Hotel, Vashi Navi Mumbai 400 703 Tel: 022-27660095

CLAMP ON PORTABLE ULTRASONIC FLOW METER The transit time flow meter measures flow rate by calculating the spreading time of an ultrasonic wave in a liquid, going upstream and downstream go into a full pipe. This flow meter is mostly used to measure the flow rate of homogeneous fluids, with a very little percentage of suspended solids and possibly without gas bubbles. Its peculiar installation makes these devices suitable for measuring aggressive fluids (acids, basic and dissolvents) or soiling fluids (oil and fuels). The measuring system is composed of one or more couples of ultrasonic transducers acoustically coupled to the external pipe’s wall (it is also possible to use transducers in direct contact with fluid to be measured) and a portable unit elaborating the sent and received signals from the transducers. The HOST unit has a DSP microprocessor; it gives signals to interfacing with the process or the control systems.

For details contact: National Instruments Corpn 12 Civil Lines Roorkee Uttarakhand 248 001 Tel: 01332)-271060

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CLAMP ON FLOW METER

GAS FLOW METER

Test & Measurement Co offers CTF878 clamp flow meters to the clients, which are known for long service life and easy to operate controls.

Iotaflow Systems Pvt Ltd is recognized as one of the prominent volumetric gas flow meters manufactures in India.

The various types of gas flow meters - GWF gas flow meter Series EQZ; GWF gas flow meter Series TRZ; GWF volume corrector ELCOR 2; SS turbine flow meter; Vortex mass flow meter; and Thermal mass flow meter offered are deally designed to measure the rate of flow of fuel gases consumed for commercial, industrial or residential purposes.

These products are made using correlation tag ultrasonic flow measurement technique that measures flow of natural gas, compressed air, inert gas or any other gases with accuracy.

For details contact: Iotaflow Systems Pvt Ltd BE 200, Lane No: 6, Hari Nagar, New Delhi 110 064 Tel: 011-25127461, 25496072, 45510992

For details contact: Test & Measurement Co No: 140, Bhagyashree Colony Opp: Vijay Nagar Police Station Indore, Madhya Pradesh 452 010 Tel: 0731-2553780 Fax: 91-0731-2577593 E-mail: tmcindore@gmail.com / info@tmcindore.com / sales@tmcindore.com / sales2@tmcindore.com

V-CONE FLOW METER

FLOW METERS

V-Cone Flow Meter is an advanced differential pressure type instruments.

V-Cone is especially useful in tight-fit and retrofit installations in which the long runs of straight pipe required by Orifice Plates, Venturi Tubes and other technologies are either impractical or unavailable.

Roxar Flow Measurement multiphase meter provides an accurate and continuous on-line monitoring of the flow rates of oil, water and gas in the oil well stream. Roxar Flow Measurement (RFM) is market leader within multiphase metering. By using RFM multiphase meters the following elements may individually or in combinations contribute to improve the overall project economics: accelerated oil production; increased oil recovery; lower investments and operational costs. The RFM multiphase meter offers the industry the best solution to optimise reservoir measurement.

Exceptional dynamic response makes well testing operations quicker and more efficient and provides valuable new information for diagnosis and optimisation of a well’s performance. These meters are more accurate than separation-based systems because they are independent of separation efficiency and insensitive to slugs, foam, carry-overs and emulsions.

The use of optimum quality materials in the manufacturing of the natural gas flow meters ensures high durability, robust structure and resistivity to adverse conditions.

With no moving parts to replace or maintain, the V-Cone offers long term performance with low operating costs. In addition, the meter never needs recalibration, so once installed; it can operate unattended for years. The installation flexibility of the V-Cone is due to its ability to condition the flow prior to measurement.

For details contact: Virtual Instrumentation & Software Applications Pvt Ltd Vision Tower No: 15-16-17, Yogam Garden Brindavan Nagar Valasaravakkam Hyderabad Andhra Pradesh 600 087 Tel: 040-24867891, 24867335 www.oswindia.com

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For details contact: Norinco Pvt Ltd G-4, Hans Bhawan, 1, Bahadurshah Zafar Marg, New Delhi 110 002 Tel: 011-23379532, 23378960 Mobile: Mr Nitin Divate Website: http://www.norinco.co.in

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products

GAS FLOW METER

ULTRASONIC FLOW METERS Jost’s Engg Co Ltd offer a highly accurate ultrasonic flow meters and coriolis mass flow meters that can take measure reliably over a very wide range of pipe sizes and flow conditions.

Accurate and versatile, their fixedinstallation flow meters provide an unrivaled combination of powerful features to meet your needs. For testing, service and troubleshooting, their portable flow meters offer the ultimate in flexibility and ease of use. Their product range includes fixed-installation as well as ultrasonic portable flow meters.

For details contact: Jost’s Engg Co Ltd Plot No: 3, Survey No: 126 Paud Road, Pune Maharashtra 411 038 Tel: 020-25434350, 25434565, 25431223 Fax: 91-020-25434393

Heatech Engineers offers good quality range of gas flow meters. These meters are used to test the flow of the gas in various pipe equipments and other gas-oriented furnaces or industrial appliances.

This meter is used in testing purposes, especially on various gas burners and gas equipments to ensure that the required amount of gas-pressure is obtained.

For details contact: Heatech Engineers No: 33/3-C, Ganesh Layout Nallampalayam Ganapathy PO Coimbatore, Tamil Nadu 641 006 Tel: 0422-6576521

INDUSTRIAL GAS DETECTION SYSTEM

Tr 600h is battery operated and come with a portable carry-case with battery charger, cables and transducer clamps. Optional magnetic clamps are available for quick installation on large M. S. & C. I pipes.

Industrial gas detection system comprises highly sensitive sensors and linear performance characteristics. These modules are placed in strategic locations and connected to the central processing unit. The indication of a leak is facilitated by the layout of the sensing modules on the CPU, through which the location of the leak can be detected. The leak is quickly detected and an audio and visual alarm is sounded to alert the user. The CPU cum display unit comprises a signal processing circuitry, which amplifies a milli-volt signal to activate the alarm. This audio alarm is supported by a visual activation of the LED on the map of the area covered to locate the site of leak. The company has the approval of CMRI, CCOE and BIS certification for their flame proof junction box. These boxes can be installed in bulk storage areas like LPG bullet yards, gas banks with multi cylinders in manifold and operation/utility areas inside factories/plants, cooking areas in food courts/canteens/kitchens. These are available for gases like LPG (Butane/Propane),NH 3, Acetylene (DA), CO and H 2.

For details contact: Acorn Controls No: 4, Mayuresh Apartments 104, Mayur Colony Kothrud, Pune, Maharashtra 411 038 Tel: 020-25422057 Fax: 91-020-25422057

For details contact: Gasvigil Technologies Pvt Ltd Saravana Complex, 8-298/1, Gautham Nagar Old Airport Road, Bowenpally, Secunderabad, Andhra Pradesh 500 011 Tel: 040-66485808, 64575808, Fax: 91-040-27843201, 23076577 E-mail: contact@gasvigil.in / info@gasvigil.in

PORTABLE ULTRASONIC FLOW METER Portable ultrasonic flow meter is a handheld battery operated portable ultrasonic flow meter.

It is a versatile portable ultrasonic flow meter for flow metering of liquids such as raw water, chilled water, potable water, DM water, oils, organic solvents, etc. Using time proven ultrasonic transit time flow metering principle, Tr 600h achieves a flow metering for pipes ranging from 15 to 3,000 mm. It is also an ideal instrument for energy audit requirements.

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FLOW METERS In order to guarantee smooth operation and consistent quality, many processes require constant in and out flow of liquid or gaseous. Flow meters measure continuously the volume per time unit relative to the defined pipe cross-section. Turck sensors apply different methods for electronic measurement of flow rates such as the calorimetric, the magnetic-inductive as well as the vortex principle.

For details contact: Reynold Automation T1-Shakti Park Apartment, B/h ABS Tower Old Padra Road, Vadodara, Gujarat 390 001 Tel: 0265-2340910, 265)-2340911; Fax: 91-0265-2340911

GAS LEAK DETECTION SYSTEM Omega Secure Engg offers gas leak detection systems for industrial applications to monitor gas leaks and shut down systems safely.

Omega Secure are dedicated to eliminate accidents on job, plan to arm every worker working in hazardous environment with portable gas detector, install fixed gas detection systems in every industrial commercial and residential locations where explosive and toxic gases are used.

For details contact: Omega Secure Engg S-5 Gr Floor, Sai Mahal Co-op Hsg Society Ltd, Nadiadwala Colony Road No: 2, S V Road, Malad (W), Mumbai 400 064

OIL AND GAS PIPELINE LEAKAGE DETECTORS For pipelines larger than 4-inch (100 mm) dia, SmartBall offers unparalleled leak sensitivity and accurate location capability. It is easy to deploy and can be used to complement existing pipeline integrity programs or as an integrity check on non-piggable lines. The device consists of an instrumented aluminum core in a urethane shell. The device contains a range of instrumentation, including an acoustic data acquisition system that listens for leaks as the ball travels through the pipeline. SmartBall differs from conventional inspection pigs. The ball is smaller than the pipe dia. It rolls silently through the pipeline and the absence of mechanical noise allows unsurpassed acoustic sensitivity.

The device can detect pin-hole size leaks as low as 0.03 gallons per minute (0.1 liters/min). This is exponentially more sensitive than CPM-based leak detection systems; and the advantage increases along with pipeline dia. Leak location accuracy is within 10 ft (3 m) and given additional reference points can be even further tightened. The device can be deployed and retrieved using existing pigging facilities. In non-piggable lines, the device can be launched using off-the-shelf fittings. Travel time is 28 hours for up to 4-inch (100 mm) lines and up to 110 hours for larger lines.

For details contact: ANK Seals Pvt Ltd U-149, M I D C Nagpur, Maharashtra 440 016 Tel: 07104-234210, 325094 Fax: 91-07104-232378

LPG SMELL DETECTOR GAS DETECTOR Axis Fire Protection offers a highly effective range of gas detector. These detectors are used to detect a gas leak and interface with a control system so that the process can be automatically shut down. Their detectors are also enabled with a sound alarm and updated features. These are scientifically designed using utmost quality factor inputs as per international quality standards.

For details contact: Axis Fire Protection Plot No: 3047, Sector-46, Gurgaon, Haryana 122 001 Tel: 0124-2579866 www.oswindia.com

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Heatech Engineers offers range of LPG smell detector. The smell detector has been recently fabricated implementing the latest digital techniques and advanced systems. This range also consists of alarm notification application along with a significant control component. All these units manufactured comprise of rechargeable batteries, which ensures continuous defense and security.

For details contact: Heatech Engineers No: 33/3-C, Ganesh Layout, Nallampalayam, Ganapathy PO Coimbatore, Tamil Nadu 641 006 Tel: 0422-6576521

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products

PORTABLE GAS DETECTOR The Series C16 PortaSens II portable gas leak detector is a versatile tool for performing regular leak checks in gas storage areas, around process equipment and piping or in confined spaces prior to entry.

Designed for easy one hand operation, the detector contains an internal sample pump and a flexible sampling wand to allow pinpoint location of the source of leakage. A large character display ensures that measured values are easily visible, and a back-light for the display ensures readability in low or no light conditions.

For details contact: Anacon Process Control Pvt Ltd 403-404, Gemstar Comml Complex Ramchandra Lane Extension Kanchpada, Malad (W) Mumbai 400 064 Tel: 022-40644333

LPG AUTOMATIC SHUT OFF DEVICE

CONVERSION FROM FURNACE OIL TO LPG GAS Model COG burners are duoblock oil/gas burners suitable for firing kerosene, HSD, LDO, furnace oil, LSHS/natural gas and LPG. Duoblock means burners are separate and associated equipment like oil pump, preheaters, gas train, combustion fan and control panel are separate units For details contact: Equip Sales & Services No: 30-A, Esteem Park Takli Phata Dwarka Nashik Maharashtra 422 001 Tel: 0253-6516461

OIL PURIFICATION & CLARIFICATION SYSTEM HMT manufactures compact oil purification and clarification system. Its application finds its best use in curbing expenditure of oil to its fullest advantages by recycling and reusing the spent oil through this recovery system.

Indus International offers excellent quality of LPG automatic shut off device. These are used for log cylinders, which saves life and saves gas as well.

The sequence of normal gas flow are: gas enters the automatic shut off device directly from the cylinder; gas is channeled into a chamber, where it passes the shutoff element; gas is then channeled up out of the chamber and past the gauge pin; and gas then exits.

The shut off mechanism works on the bernoulli principle. A sudden increase in gas flow (for example from the hose rupturing) changes the pressure around the shut off element, lifting it up and causing it to plug the exit to the chamber and stop the flow of gas completely. The shutoff element will stay in this position until you push down on the gauge. The gauge pin then pushes the shutoff element back down into the chamber, so resetting it ready for normal operation.

For details contact: Indus International E-133, Greater Kailash-1 New Delhi 110 048 Tel: 011-41633313

The 1,000 lph oil purification and clarification system OPCS-01 is well suited for purification and separation of water from mineral oil, as well as for separation of liquid mixtures or for the purification of fluid from solid constituents (dirt, dust, etc). The high efficiency of separation of the two liquid phases is achieved by choosing the suitable regulating disc. The high efficiency of the clarification is achieved by minor manual adjustment in the purification bowl.

HMT’s unique bowl design makes it possible to use the separator both as purifier and as clarifier with minor adjustments only.

For details contact: HMT Ltd H-2, M I D C, Chikalthana Indl Area Aurangabad Maharashtra 431 006 Tel: 0240-2485008, 2485596 Fax: 91-0240-2485007

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events diary 21 st World Petroleum Congress Date: June 15-19, 2014 Venue: Russian Exhibition Venue, Crocus Expo, Moscow, Russia Event: The 21 st World Petroleum Congress and Exhibition (WPC Exhibition) and the World Petroleum Exhibition associated with the Congress will take place in Moscow, Russia at Crocus Expo on June 15-19, 2014.

Venue: Kuwait Regency Palace Hotel, Kuwait City, Kuwait Event: The 2013 Kuwait Oil & Gas Summit & Exhibition, hosted by the Kuwait Petroleum Corporation (KPC), is one of the most important events related to the Oil & Gas sector in Kuwait. This leading event will start on 28 April 2013 and will bring together senior decision makers in the Kuwait and international oil and gas industry to highlight the opportunities and challenges of Kuwait energy in a global context, focusing on the development, diversification and growth of the economy.

Since the first WPC event in 1933, it has grown to become the largest and most prestigious event in the global oil and gas industry and has been held every three years in one of its more than 65 member countries. In its 80 th Anniversary year the Congress is continuing to achieve new heights and further unite the members of the global petroleum community.

Focusing on innovation and international collaboration, the Summit will discuss the investment opportunities needed to meet KPC oil production targets and promote industry growth.

The theme of the 21 st WPC is ‘Responsibly Energising a Growing World’. The Congress Programme Committee has prepared a wide-ranging Technical Programme to recognise the scientific, technological and professional achievements of the oil and gas industry.

The largest Russian exhibition venue, Crocus Expo in Moscow, has been selected as the venue for the 21 st WPC.

For details contact: The CWC Group Limited Regent House, Oyster Wharf 16-18 Lombard Road London, England, United Kingdom Tel: +(44)-(20)-79780000 Fax: +(44)-(20)-79780099 Nigeria Oil & Gas Technology Exhibition Date: June 4-6, 2013 Venue: Eko International Expo Centre, Victoria Islands, Nigeria Event: Being hosted at Victoria Islands New Expo Centre, Nigeria Oil & Gas Technology Exhibition is renowned trade fair for oil and gas exhibition. The 3-day show will offer unlimited business potential for capitalising emerging opportunities of Chemicals & Dyes sector. The show will be organised by The CWC Group Limited.

For details contact: World Petroleum Council Suite 1, 4 th Floor, 1 Duchess Street London, W1W 6AN Tel: +44 (0)20 7637 4958 Email: info@world-petroleum.org Colombia Oil & Gas Exhibition 2013 Date: April 9-11, 2013 Venue: Cartagena Centro de Convenciones y Exposiciones Cartagena, Colombia Event: Colombia Oil & Gas Exhibition will provide the platform for international partners to meet with their Colombian counterparts, develop relationships and discuss opportunities and strategies for realizing project potential. The Colombia Oil and Gas Summit is the leading event, bringing together all the major stakeholders in Colombia and their International counterparts. Exhibiting at Colombia Oil and Gas will give you access to this lucrative market and allow you to benefit from the lucrative deals on offer in this region of great potential.

For details contact: The CWC Group Limited Regent House, Oyster Wharf 16-18 Lombard Road London, England, United Kingdom Tel: +(44)-(20)-79780000 Fax: +(44)-(20)-79780099 Kuwait Oil and Gas Summit & Exhibition Date: April 28-30, 2013 www.oswindia.com

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For details contact: The CWC Group Limited Regent House, Oyster Wharf 16-18 Lombard Road London, England, United Kingdom Tel: +(44)-(20)-79780000 Fax: +(44)-(20)-79780099 17 th International Conference & Exhibition on Liquefied Natural Gas (LNG 17) Date: 16-19 April 2013 Venue: George R. Brown Convention Center,- Houston, Texas Event: The LNG series of events are considered to be the premier global LNG events, and this is the ONLY event conducted specifically by the LNG industry for the LNG industry. LNG 17 will be the biggest global gas event to take place this year, and the next International Gas Union event, attracting decision makers and gas industry experts from all over the world.

For details contact: Jay Copan: jcopan@lng17.org Tel: +1 919 740 7799

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book shelf OIL AND GAS: INFORMATION ON SHALE RESOURCES, DEVELOPMENT, AND ENVIRONMENTAL AND PUBLIC HEALTH RISKS Author: United States Government Accountability Office A Price: USD 24.95 P Pages: 70 pages P Pu b l i s h e r : Cre ate S p a ce I n d e p e n d e nt Publishing Platform (November 20, 2012) Book Description: New applications of horizontal drilling techniques and hydraulic fracturing--in which water, sand, and chemical additives are injected under high h h pressure to create and maintain fractures in underground formations--allow oil and natural gas from shale formations (known as “shale oil” and “shale gas”) to be developed. As exploration and development of shale oil and gas have increased--including in areas of the country without a history of oil and natural gas development--questions have been raised about the estimates of the size of these resources, as well as the processes used to extract them. GAO was asked to determine what is known about the (1) size of shale oil and gas resources and the amount produced from 2007 through 2011 and (2) environmental and public health risks associated with the development of shale oil and gas.

He uses lots of pictures, graphs, and illustrations to aid readers in understanding topics and to provide necessary visuals.

OFFSHORE RISK ASSESSMENT: PRINCIPLES, MODELLING AND APPLICATIONS OF QRA STUDIES (SPRINGER SERIES IN RELIABILITY ENGINEERING) Author: Jan-Erik Vinnem A Price: USD 209.00 P Pages: 603 pages P Publisher: Springer; 2nd ed. 2007 edition P (December 10, 2010) Book Description: Offshore Risk Assessment was the first book to deal with quantified risk assessment (QRA) as applied specifically to offshore installations and operations.

This book is a major revision of the first edition. It has been informed by a major R&D programme on offshore risk assessment in Norway (2002-2006). Not only does this book describe the state-of-the-art of QRA, it also identifies weaknesses and areas that need development.

Offshore Risk Assessment was the first book to deal with quantified risk assessment (QRA) as applied specifically to offshore installations and operations. Risk assessment techniques have been used for more than three decades in the offshore oil and gas industry, and their use is set to

expand increasingly as the industry moves into new areas and faces new challenges in older regions. This updated and expanded second edition has been informed by a major R&D programme on offshore risk assessment in Norway (2002–2006), and reflects the trend of expanded use of floating production installations. It starts with a thorough discussion of risk metrics and risk analysis methodology with subsequent chapters devoted to analytical approaches to escalation, escape, evacuation and rescue analysis of safety and emergency systems. Separate chapters analyse the main hazards of offshore structures: fire, explosion, collision and falling objects. Risk mitigation and control are discussed, as well as an illustration of how the results from quantitative risk assessment studies should be presented. The second edition has a stronger focus on the use of risk assessment techniques in the operation of offshore installations. Also decommissioning of installations is covered. Not only does Offshore Risk Assessment describe the state of the art of QRA, it also identifies weaknesses and areas that need further development. A comprehensive reference for academics and students of marine/offshore risk assessment and management, the book should also be owned by professionals in the industry, contractors, suppliers, consultants and regulatory authorities. Dr Jan Erik Vinnem is Professor of Risk Analysis and Management at the University of Stavanger. He is a Specialist Advisor and CEO of Preventor AS, a small consultancy to the Norwegian offshore industry. His professional career includes several years in the petroleum industry (Statoil, Total), over 20 years in consultancy and some years, now expanding, in research and education.

CORPORATE SOCIAL RESPONSIBILITY FAILURES IN THE OIL INDUSTRY [HARDCOVER] Editor: Charles Woolfson , Matthias Beck Ed Price (INR): ` 259.80 P Pages: 170 pages P Publisher: Baywood Pub Co (March 2005) P Book Description: This book directly challenges the oil industr y’s claims of corporate good citizenship, now widely advanced as part of a global public relations offensive. The volume spans the industry’s reach, from the troubled waters of the U.K. offshore Continental Shelf, with its horrendous legacy of the Piper Alpha oil rig disaster, to the inhospitable shores of Newfoundland, with its own tragic legacy of lost lives, to the new frontier of oil corporate colonialism in the former Soviet Union and the icy plains of Alaska. The central theme of violations of basic labor rights and of health and environmental protection standards will make uncomfortable reading in the boardroom. It is equally essential reading for those who seek to improve the position of workers and communities within the oil industry’s global reach. It is essential reading for those who wish to peer behind their public relations facade.” -- Jake Molloy, General Secretary, Offshore Industry Liaison Committee (UK offshore oil workers’ trade union)

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FORM IV Statement about ownership and other particulars about newspaper OFFSHORE WORLD to be published in the first issue every year after the last day of February 1.

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Names and Addresses of individuals who own the JASUBHAI MEDIA PVT LTD., newspaper and partners or shareholders holding more 26, MAKER CHAMBERS VI, NARIMAN POINT, MUMBAI 400 021 Jasu Ramniklal Shah, Shweta Jasubhai Shah, Maulik Jasubhai Shah, than one per cent of the total capital Maulik Business Services Pvt. Ltd, (1100, Shanudeep, 10, Altamount Road, Mumbai 400 026), Jasubhai Business Services P Ltd., (26, Maker Chamber VI, Nariman Point, Mumbai 400 021

I Maulik Jasubhai Shah, hereby declare that the particulars given above are true to the best of my knowledge and belief.

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