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contents INTERVIEW ‘Gas price hike will augment production’ VOL. 10 NO. 5 AUGUST-SEPTEMBER 2013 MUMBAI ` 150

- T K Ananth Kumar, Director (Finance), Oil India Limited

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interview

‘Gas price hike will augment production’ Oil India Limited (OIL) is one of the domestic E&P players in the upstream sector. The depreciation of rupee against the dollar is going to work out favorably for upstream companies. The doubling of gas prices from USD 4.2 per mmbtu to USD 8.4 per mmbtu will bring improvements in margins of OIL. T K Ananth Kumar, Director (Finance), Oil India Limited, talks to Offshore World about impact of Rupee depreciation against Dollar on oil and gas industry, subsidy sharing, OIL’s plans of foraying into refining sector, pros and cons of recently presented Land Acquisition Bill in Parliament, and many more. Excerpts:

T K Ananth Kumar Director (Finance) Oil India Limited

How will the recent drastic Rupee depreciation against Dollar impact the country’s oil & gas industry value chain when India is already footing high oil imports bill? What would be the balancing act the companies will have to perform to maintain their profitability?

India’s oil and gas industry is primarily divided in two sectors with companies like OIL and ONGC in the upstream sector and IOC, BPCL, HPCL in the downstream sector. Since the price of oil and gas produced by OIL and ONGC are USD denominated, the depreciation of Rupee works out favorably for the upstream companies.

However, for the downstream marketing companies, the Rupee depreciation definitely has adverse financial implications as rising cost of crude oil increases their under-recoveries on sale of diesel, PDS kerosene and domestic LPG, which may adversely affect upstream companies through increase in discounts to OMCs. As far as crude price is concerned, it is difficult for anyone to exactly predict the oil price in the future. However,

any geopolitical disturbances has the tendency to affect the crude oil price adversely, though it may not be long lasting incidentally crude oil price has been quite steady over the last 30 months or so with an average of around 110 USD per barrel.

OIL is having overseas investments in various E&P assets in different geographies of the world. To the extent, we finance these overseas projects out of our internal resources. The investments in projects in Rupee terms increase due to fall of Rupee. However, from the assets, which are already producing like Carrizo, the revenue generation is also in USD, which reduces the adverse Rupee depreciation impact to some extent.

What are your views on the Government’s intent on bringing changes in the subsidy regime and intends to now pass it on to the oil producers which were earlier only borne by the Oil Marketing Companies? How is this going to hit the top & bottom line margins of oil producers?

>>The need of the hour is to have a transparent and predictable subsidy sharing mechanism devoid of adhocism, which would help both the upstream and downstream companies to plan their cash flow properly. We have represented to Govt and also to Kiritimati Parikh Committee suitably and are hopeful that a clear cut mechanism of subsidy sharing would be soon put in place. www.oswindia.com

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Offshore World | 6 | AUGUST - SEPTEMBER 2013

04-10-2013 10:42:59

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Right from the beginning of subsidy sharing mechanism in 2003-04, OIL, ONGC and GAIL are bearing a substantial portion of the subsidy on marketing of sensitive petroleum products by the Oil Marketing Companies. The contribution by oil producers has ranged in between 30 per cent to 42 per cent during the last several years.

Though we are bearing a substantial portion of the subsidies, over the years the Government has ensured to some extent that the crude oil producers get a reasonable net price realization. However, the need of the hour is to have a transparent and predictable subsidy sharing mechanism devoid of adhocism, which would help both the upstream and downstream companies to plan their cash flow properly. We have represented to Govt and also to Kiritimati Parikh Committee suitably and are hopeful that a clear cut mechanism of subsidy sharing would be soon put in place.

May we have your comments on the recent announcement of Government on hiking gas prices from USD 4.2 to USD 8.4 mmbtu instead of deregulating the gas prices when this trend has actually been able to address the gas supply deficit in the many countries?

What the Government has approved is a formula for linking the prices of domestically produced natural gas to the prevailing international prices and based on that formula the indicative price worked out to USD 8.4 per mmbtu. The new pricing system, when implemented effective from April 2014, will link the price of domestically produced natural gas to the international prices and the prices will be floating on a quarterly basis in line with international prices.This price increase would encourage producers to undertake more and more investments in exploration, which would help in more production and hence less dependent on imported gas as gas business would become increasingly viable with higher realisations.

According to the media reports, Oil India has now plans to foray into the refining sector. What is the rationale and please share some insights into the planned project with reference to the capacity, site, investment, funding, product lineup, future expansions and adding downstream units www.oswindia.com

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>>With an intention to get on hand experience in the shale exploration, OIL has acquired 20 per cent stake in a shale oil asset in USA which is also giving us consistent revenue since acquisition and has improved Company’s international visibility. etc? Would you be also looking at roping in international partners?

OIL already has 26 per cent stake in Numaligarh Refinery in the state of Assam. In line with our policy of selective diversification, we are looking for partnerships in more such refinery projects.

However, a decision about the size of our participation in the project will be taken by the management at appropriate time as and when some good opportunity is available. We also wish to reiterate that our primary focus shall continue to be E&P and diversification would be very selective in value chain with good economics.

Does Oil India intend to get into shale gas exploration at some point of time?

OIL will certainly go for shale gas exploration as and when the Government of India’s shale gas policy is announced and the exploration activities commence. With an intention to get on hand experience in the shale exploration, OIL has acquired 20 per cent stake in a shale oil asset in USA, which is also giving us consistent revenue since acquisition and has improved company’s international visibility.

How favourable is Land Acquisition Bill presented recently in the Parliament for the industry in your opinion?

We are already facing some difficulties in land acquisition for our E&P activities. The new Land Acquisition Bill to the extent we understand at present may make such acquisitions a bit more costly. We are yet to get a full insight into the new legislation and are, however, hopeful it may reduce the time gap being taken for land acquisition.

With the next round of bidding for NELP just around the corner, what are your thoughts on the success of attracting investments into the country after the gas price revision by the Indian Government?

With the announcement for increase in the natural gas price by the Government of India and

linking it with the prevailing international prices from time to time, the Government has made its intention clear that the country is looking for more investments in the E&P sector and the Government is willing to facilitate such investments. We expect good participation in the Xth Round of NELP after clarity on gas pricing.

Please apprise us about the status of OIL’s Mozambique asset purchase?

OIL along with OVL has signed a definitive agreement for acquisition of Videocon’s 10 per cent stake in Mozambique’s Rovvuma basin at a price of USD 2.475 billion. We are awaiting approval of the Government of India for this deal. Once the deal is finalised, this will be the single largest investments

by OIL overseas so far in a giant oil field.

What is OIL’s CAPEX for 2013-14 and how does the company plan to invest it? Please share the overseas acquisition plans lined up for the near future.

OIL has drawn plans for investment of USD 600 million for 2013-14. Out of this about 80 per cent investments will be in the E&P activities within the country with remaining expenditure being incurred in the ongoing overseas projects. Apart from the ongoing overseas projects, presently we are in the process of closing the Mozambique deal.

In the current turbulent times, what strategy is Oil India adopting to maintain and accelerate the growth momentum?

OIL has drawn a Strategic Plan for medium term till 2020. Our main strategies include maintaining and enhancing production from current fields through various means including EOR/IOR activities, accelerated exploration initiatives, inorganic growth (both within India and overseas) and selective diversification. sw

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features Recovery Technology

Enhanced Recovery through Subsea Compression Subsea gas processing is the application of hydrocarbon processing equipment at the seafloor for conditioning and pressure boosting of reservoir stream fluids. Reservoir pressure in producing gas fields falls over time, causing gas output to decline. The article illustrates that how does the Subsea Compression System help in increasing the reservoir pressure in subsea gas processing to achieve the desired plateau rate.

In recent years, subsea gas processing has been recognised as one of the most promising technology developments in the offshore industry. Subsea gas processing is the application of hydrocarbon processing equipment at the seafloor for conditioning and pressure boosting of well stream fluids. With the recent successes at Åsgard Subsea Compression - Statoil and Ormen Lange Subsea Compression Pilot - Shell, subsea compression is attracting interest worldwide from industry because of its ability to increase production, enhance reservoir recovery and improve field economics.

At low flow rate, velocity of gas is not sufficiently high to continuously move liquid out of the pipeline; this condition is referred to as minimum hydraulic limit at which production cannot be sustained.

As compressor maintains flow rate of gas above hydraulic limit for some more time as compared to production by natural pressure, more hydrocarbons can be recovered from the reservoir as illustrated in Figure 2.

Massive technology qualification programme has been part of Åsgard Subsea Compression and Ormen Lange Subsea Compression Pilot projects in which a large number of products have been qualified for use for subsea gas processing.

Subsea compression is, in general, still considered as an emerging technology.

Therefore the benefits and capabilities must be clearly demonstrated to become the most preferred option.

Production Rate and Recovery Initial reservoir pressure is usually sufficiently high enough for production by natural pressure for a number of years through a pipeline system connecting to topsides facilities. However, since production is invariably accompanied by a decline in reservoir pressure, plateau production soon comes to an end and starts its decline.

Pressure boosting the well fluid at this stage reduces the wellhead pressure on the wellhead and thus increases the production as seen from Figure 1.

Figure 2: Daily Production

The Åsgard subsea gas compression project, with its two trains of state-of-the-art 11.4 MW subsea compressors, is expected to add recovery of an additional 280 million BOE. Pipeline Sizing Sizing of pipelines is traditionally made by finding a compromise between investment cost and available flow area. Large pipes are required at the end of field life to maintain high production rates when reservoir pressure has declined.

Figure 1: Cumulative Production

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As gas production rate substantially reduces, the pipe reaches a hydraulic limitation characterised with the velocity of the gas which is no longer high enough to force the liquid out of the pipe. As it has been acknowledged that subsea compression will be qualified and available as required at the end of field life, it should be considered at the conceptual phase with regard to determining pipeline size.

Offshore World | 10 | AUGUST - SEPTEMBER 2013

04-10-2013 10:50:53

>> Initial reservoir pressure is usually sufficiently high enough for production by natural pressure for a number of years through a pipeline system connecting to topsides f a c i l i t i e s. However, s ince p ro d u c t io n i s i nvari abl y accompanied by a decline in reservoir pressure, plateau production soon comes to an end and starts its decline.

When a compression station is foreseen in late life operation, the selected pipeline may be made smaller since fric tional pressure drop can be overcome by compressor power and velocity of gas can be maintained above hydraulic limitation.

different functionalities, as long as interconnections and control system is planned for.

Modular design gives enough flexibility to cater to the changing requirements of producing gas field throughout its life.

Figure 3 shows a process train of Åsgard Subsea Compression Project, which comprises a inlet and discharge gas coolers, liquid separator and compressor modules, with the latter due to be powered from the Åsgard A oil production ship.

The subsea compression development will expand capacity in the Åsgard Transport pipeline, which carries gas from Norwegian Sea installations to the Kårstø plant north of Stavanger.

Compressor Location – Why Subsea?

Compression of gas may be done at three different locations in gas producing network: 1) At Onshore End: This is the cheapest of all other option but is inefficient.

Excessive energy is required to pull gas from subsea wells through pipeline net work to onshore. Enhancing produc tion by reducing well head pressure with this method would not be efficient due to ver y high pressure loss in the pipeline, caused by expansion of gas at lower compressor suction pressure which results in high actual volume flows.

Volume expansion of gas is relatively much higher in lower pressure compared to higher pressure. A higher actual flow also leads to higher compressor power.

2) At Offshore: In this option, compressor is located nearer to the producing wells than the earlier option. However additional pressure drop may be created in the riser systems from the wells to the platform processing facilities, especially when platform is located in deep waters. Also this option incurs more capital cost as it needs suitable platform (either fixed or floating) for installing compressor and other facilities.

Figure 3: Åsgard Subsea Compression Train – Process System with Structure Courtesy: Aker Solutions

Compact Design of Subsea Gas Processing Station for Smaller Gas Fields Realizing the need of production from smaller gas fields, subsea gas processing systems for fields, can be configured in one single integrated, compact, retrievable unit of reduced capacity of typically 2-10 MW. The Compact GasBooster (Figure 4), which will enable the use of gas compression on a wider range of fields (small to medium size gas fields) and is well suited for deep water applications.

The proposed solution is of the same type as for Åsgard Subsea Compression System, however in a significantly smaller scale and with a simplified integrated and compact arrangement.

3) At Subsea: This is nearest possible location to the producing wells and is most efficient and needs less power as compared to other option discussed. It could add more economic value to the field if it is planned and considered in the field development plan at the early stage.

Modular Design of Subsea Gas Processing Station for Large Gas Fields For large Gas fields such as Ormen Lange and Åsgard, subsea gas processing infrastructure can be modularised, consisting of a number of retrievable process modules. Each module will have a dedicated processing function. Together all the process modules installed and connected will perform the processing of the well fluid required.

Connections between modules will be made by mechanical and electrical connectors. A subsea process plant may therefore easily be configured for

Figure 4 : Compact GasBooster in comparison with Ormen Lange Subsea Compression Pilot Process Train Courtesy: Aker Solutions

Offshore World | 11 | AUGUST - SEPTEMBER 2013

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A GasBooster with a compressor utilizing 6 MW shaft power has been considered in an integrated system process simulation. The compression station is physically located near to the production wells. Furthermore, pipeline inlet pressure is 11 MPa. The compressor has a pressure ratio capability of 1:5.

When plateau production no longer can be sustained by natural pressure, compression power is gradually increased to achieve the desired plateau rate. At a certain reservoir pressure, the compressor power is insufficient to maintain the plateau production. Hence, the rate corresponding to 6 MW input is produced.

Yearly production rates and accumulated production for production with natural pressure are in the following Figure 5 & Figure 6 compared with what is achievable with pressure boosting.

The compressor power and pressure ratio is illustrated in Figure 7 below for declining reservoir pressure. Production is ended when a compressor ratio higher than 1:5 is required to maintain a minimum flow rate of 200 MMSCFD.

Figure 7: Compressor Power and Pressure Ratio against Reservoir Pressure

Summary The selection of subsea compression for Ă…sgard and Ormen Lange in a fully sanctioned commercial project rather than opting for a new compression platform, Statoil and Shell has demonstrated that this technology is fully market-ready.

In order to get full economic value out of the field, E&P companies should consider employing this technology at the feasibility and conceptual stage of the development plan.

Figure 5: Daily Production with Natural Pressure and Pressure Boosting

Figure 6: Accumulated Production with Natural Pressure and Pressure Boosting

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As it has been realised that the large producing fields like Ormen Lange and Ă…sgard are limited, more number of smaller fields are getting attention of E&P companies.

Single, integrated, compact, retrievable unit of reduced capacity of typically 2-10 MW can be designed for smaller fields. sw

Avinash Darekar Designation-Principal Engineer | Area Engineering & Module Design Subsea Power & Process I, Aker Solutions

Offshore World | 12 | AUGUST - SEPTEMBER 2013

04-10-2013 10:50:55

features Innovative Technology

The Buoyant Tower & Floatover Concept The oil and gas industry is known for innovations. It pushes the limits of subsea exploration as deepwater fields and wells are drilled even deeper and located further offshore. So, it’s no surprise that a new generation of oil platform has been designed. The first of its kind, the Buoyant Tower which currently sits in the Pacific Ocean, may well revolutionise exploration and production around the world.

Designed to reduce the overall timelines from offshore exploration to production, Buoyant Tower concept facilitates the fabrication and installation of a drilling and production platform. While enabling reduced project timings and costs, it provides the flexibility to re-use and re-locate the Buoyant Tower anywhere in the world.

Comprising four cylindrical tubes with one central suction pile, each cell measures 8.4 meters / 28 feet in diameter and 60 meters / 197 feet in length.

The central suction pile integral to the full structure attaches the structure to the seabed. On top of the 2,500 ton Buoyant Tower hull sits a 1,500 ton platform where the production drilling is carried out. Suitable for water depths between 50 and 280 meters / 165 to 920 feet, it can be used in any type of field with any variation of reservoir characteristics – oil, gas or a combination, and the drilling can be modularised to adapt to the needs of the operation.

The tower is designed on existing cell spar technology and due to the simplicity of the cellular components of the hull, it falls in the category of a ‘compliant structure’ – one that accommodates the dynamic forces through flexibility instead of resisting the loads rigidly, thereby limiting the internal dynamic loads - and is less expensive than fixed platform alternatives. Similarly, the system is well suited for regions with seismic activity better than a traditional fixed platform.

The topside and fabricated tower of a production platform – which can vary dramatically in weight from less than 1,000 tons to more than 40,000 tons - are first loaded onto a heavy vessel for transportation to its offshore installation location. The vessel then submerges to allow the tower to float off, while the topside remains on-board supported by a truss system. Once the tower is in an upright position, it is towed close to its final destination.

>> The tower is designed on existing cell spar technology and due to the simplicity of the cellular components of the hull, it falls in the category of a ‘compliant structure’ – one that accommodates the dynamic forces through flexibility instead of resisting the loads rigidly, thereby limiting the internal dynamic loads - and is less expensive than fixed platform alternatives.

The critical float-over operation, which involves placing the topside over the tower to connect the two together can then begin.

An important aspect of the design is to help dampen the loads while performing the float-over; the crucial challenge being to transfer the load from the topside to the tower mating points in a controlled manner without causing damage to either structure.

Traditionally the topside is lifted on to the tower or substructure by an offshore heavy lifting crane, however, the rates for hiring these can be very high - sometimes running into several hundred thousand dollars a day. Using leg mating units (LMUs) and deck support units (DSUs) will provide a much more cost effective solution and offers a proven technology and successful installation method for offshore constructions.

A major cost saving benefit of the Buoyant Tower design was that only one major construction vessel was needed for the installation procedure.

This project was the first cantilevered float-over operation from a heavy transportation vessel. The motions of the transportation vessel and the design of the cantilever structure had to be thoroughly evaluated.

In addition, the float-over process enables nearly all of the work on the topsides to be completed in the fabrication yard resulting in much lower labor costs.

Engineering Elastomeric to Cushion the Impact Forces The LMUs which consist of steel struc tures incorporating engineered elastomeric pads make the transition possible by dampening the forces created

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>> A major cost saving benefit of the Buoyant Tower design was that only one major construction vessel was needed for the installation procedure. This project was the first cantilevered float-over operation from a heavy transportation vessel. The motions of the transportation vessel and the design of the cantilever structure had to be thoroughly evaluated. as the topside’s load is transferred to the tower. The elastomeric pads are designed to take up the static and dynamic forces of the topside structure, as well as the horizontal forces due to open sea motions during the float-over mating operation. The vertical elastomer pads are normally complemented with horizontal elastomeric pads to cater for this movement.

Using data provided by the offshore consultants on the expected loads and movements, the elastomeric pads are carefully engineered and calculated with non-linear finite element analysis (FEA), to achieve the expected spring stiffness for this crucial task.

The assembled LMU can be installed either on the topsides or jacket. In this recent Buoyant Tower project, LMUs were installed underneath the topsides with deck leg casing. The LMU receptor heads and stabbing cones, welded to the tower, were the contact points between the topside and the tower.

DSU’s are also important components for safe float-over operations. The topside is loaded onto the vessel with a deck support frame and the DSUs are then placed between them to absorb the weight of the topsides. This enables the LMUs and DSUs to work together in synchronization. When the heavy vessel starts to ballast, decompression will occur on the DSUs and vertical compression will occur on LMUs. The fendering systems are commonly used to absorb the impact of the heavy vessel and the tower as it moves forward or sideways during the mating operations. After the installation is completed, the topside structure is welded to the tower. This concept can also be applied to SPAR, Semi-Submersible or TLP design.

Stringent Quality Control and Testing Requirements Weather and sea state conditions are often affected by location, which naturally impac ts on vessels in numerous ways making it imperative to t h o ro u g h ly te s t t h e s p e c i f i c co m b i n at i o n o f we at h e r a n d ve s s e l for each application.

With the ability to perform full-size LMU compression testing to maximum design factored load capacity, clients should specify units which are tested using a press with a capability of 18,300 MT, for the most accurate results.

All LMU elastomeric pads shall be tested to verify their non-linear stiffness behavior, before the site installation occurs.

Designed to Perform With a large amount of load placed on the elastomer pads during the floatover process – both physically and metaphorically – it is key that a high performance product is specified. Without second chances, ever y effor t must be made to achieve perfection. To ensure this, an understanding of the characteristics and benefits of the elastomeric materials used in the float-over process are important. For example, the number of elastomeric layers and its size, will influence the vertical non-linear stiffness.

Conclusion Innovations within the offshore oil and gas industry have developed rapidly in recently years. As the unpredictable environment continues to produce new challenges, concepts such as the new Buoyant Tower will remain. Due to the high stakes involved in offshore oil platform construction, specifically during the complex float-over process, it is imperative that only the most advanced products and solutions are used.

With this in mind, it is vital to work closely with an experienced designer and manufacturer that can offer world class design engineering and comprehensive testing programs, to ensure optimum solutions and compliancy with all international standards. sw

FEA design calculations are carried out to identity the high stress build-up area and potential of buckling due to the unstable elastomeric column. Fullsize tests help to validate the performance characteristic of the LMU design during the mating process.

JP Chia Engineering Manager, Trelleborg Offshore and Construction, Singapore www.oswindia.com

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features Safety Offshore

Safe & Efficient Operations in Deepwater Oil and gas industry is one of the most favoured industries in the industrial sector as many professionals opt to make a career out of it. However, it is also considered to be one of the most potential high risk areas to work under, as it deals with the exploration and production of flammable liquids. This article mainly discusses and emphasises safety issues that arise in deep marine conditions as this particular location deals with the exploration and production of petroleum.

The article not only strikes out safety issues encountered during the construction phase, but also during the operation phase once an offshore structure has been constructed and installed.

Petroleum which supports most of the daily human activities could be found on both, land as well under the ocean. There are two distinct terms which describe the location of exploration and production of oil and gas, viz, Onshore and Offshore. Onshore can be referred to as a location on land where petroleum is found and then explored, whereas exploration of petroleum in open sea can be termed as an offshore area. An Offshore platform is situated in deep sea wherein water depth could reach more than 2,000 meters.

Construction and operations in deep marine conditions have significant differences when compared to onshore operations or other non-oil and gas projects. Installation of offshore infrastructure also involves numerous equipment’s, tools, labourers and funding. The rent for an accommodation and crane barge for installing a new structural part of existing fixed platforms on an offshore location for a period of 24 hours could cost around USD 100,000. One can only imagine the amount that needs to be spent on a large scale project.

The offshore industry deals with an unusual combination of problems from the safety point of view. They include: • High pressure systems up to 300 bar and sometimes to 500 bars; • A high (300 tonnes) inventory of explosive and flammable material; • Extensive electrical system, often at voltages as high as 6.6 KV; • Large scale machinery such as gas turbines, compressors and pumps; • All plants placed in a confined space; • Living quarters very close to a working plant; • Evacuation of personnel difficult if not impractical in the most adverse weather conditions; • Installations, all individually designed to meet specific requirements; • Installation life of 20 to 30 years; • Installation to be modified during their life, to meet changes in field behaviour.

Case Study The Tragedy of Piper Alpha (1988) could give brief a view about the importance of safety in the offshore industry. Piper Alpha was a North Sea oil production platform operated by Occidental Petroleum (Caledonia) Ltd. The platform began production

in 1976, first as an oil platform and then later converted to gas production. An explosion and the resulting oil and gas fires destroyed it on 6 July 1988, killing 167 men, with only 61 survivors. The death toll includes two crewmen of a rescue vessel. Total insured loss was about USD 3.4 billion. At the time of the disaster, the platform accounted for approximately 10 per cent of North Sea oil and gas production, and was the worst offshore oil disaster in terms of lives lost and industry impact.

Piper Alpha Offshore Disaster Place: North Sea Operator: Occidental Petroleum (Caledonia) Ltd Year: 6 July 1988 Killed: 167 Survived: 61 Total Insured Loss: USD 3.4 billion Identifying Hazards Safety issues on deep marine construction need to be taken into account by stakeholders, oil company, engineering consultant, installation contractor and other vendors. First step to deal with safety issues is the identification of a hazard. Hazard is anything that has a potential to cause harm (e.g., chemicals, fire, explosion, electricity, a hole in the ground, etc.). Hazards usually occur from machines and processes, emissions, radiations, etc.

Hazards to Humans During an installation sequence at an offshore site, there are quite a lot hazards that could happen to humans. One of them is skin contact by chemicals

>> Safety issues on deep marine construction need to be taken into account by stakeholders, oil company, engineering consultant, installation contractor and other vendors in identifying of hazard like chemicals, fire, explosion, electricity, a hole in the ground, etc that occur from machines and processes, emissions, radiations, etc.

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>> The presence of too many equipment’s, tools, machines, raw materials, structural parts, and the limitation of space on the platform, work and transportation barges, could create an entrapment for the worker. In such a scenario, a situation involving fire/gas release or explosion could prove fatal. which have an immediate destructive effect. However, type of chemicals used during offshore installation or operation has no immediate destructive effect. They are harmful to human skin, but not so destructive and could be prevented. For instance, various types of liquids for topside painting, oils used as lubricant for machines, crude oils, various types of chemical liquids used for operation purpose. But skin damage caused from petroleum products could have fatal effects. It could trigger possible cancerous effects in case of long-term exposure.

Hydro test of piping on topside platform could also have hazardous effects.

High-pressure jets by air penetrations into the bloodstream can cause death. In addition, all materials nearby the hydro test area are hazards to humans.

Eye contact by spray, mists, high vapour concentrations and harmful rays can be classified as hazards. Grinding activities during installation phase is one of the sources of small particles that could hurt someone’s eye. Moreover, fire from welding activities is also harmful to a worker as the glow emitted due to the welding process is of high intensity and could damage the retina.

Hazards from Machines and Processes Hazards from machines and processes on deep marine construction condition usually occur from cranes and welding machines. Welding machines are situated on topside platforms; they could be positioned at cellar, sub-cellar, or top deck. These welding machines run on high electricity voltage and flammable fuels. Since all these locations are near to heavy working locations, there is a possibility that a worker may come in contact with a welding machine which is in operation. Furthermore, once the platform has been commissioned and operated, there would be another hazard which arises

from processes itself. Improper installation and lack of maintenance of all parts of infrastructure for supporting the processes would be hazardous.

Hazards from Emissions Machines and engineered process plants produce waste streams, these are unwanted emissions. The unwanted emissions are burnt out before they are released to the air.

Carbon monoxide (CO) emitted from welding machines, power machines, cranes, and other machinery is released in the air and often finds its way and enters the work area, which could lead to an unwanted hazard. During installation of structural parts of offshore platforms, welding cannot be avoided. As a consequence, Non Destructive Test (NDT) is also required. For particular joints, NDT has to be performed using X-ray or radiography method. Radiation of from that activity is classified as a hazardous emission. In addition, water pollutants generated as a result of human activities on the accommodation barge could also have hazardous effects on human health. Hence, unwanted wastes from food have to be collected properly, and not disposed directly into the sea. Other emission that occurs during construction and operation on deep marine condition is noise emission in the form unwanted sound produced by working machinery and plant. It could be continuous, intermittent, or erratic, depending on the source. Noise could cause hearing damage. Ability for communication could be also affected by noise; therefore important consideration needs to be taken into account for designing control rooms or cabins.

Hazards from Circumstances The latent energies are hazardous, which if released could pose danger to life and limb. Potential energy is one of the latent energies, for example, people or loads falling from a height. Riggers, during installation stage on deep marine condition are people who have the highest risks with regards to this hazard.

They have to climb to a particular height for assisting the crane operator during moving and placing of an object from one point to another. Moreover, lifted objects are those which have latent energies and all workers standing up on lifting region have risks. Other latent energy is kinetic energy release. It could be due to explosions, release of moving components due to failure of pressure vessels, components of engines and vehicles, etc.

Dangers from electrical energy could be occurred due to live components, insulation problems, or residual stored energy. Competent engineers who have already worked for this field have to ensure that all electricity sources are well maintained and well controlled during installation phase, as well as during operation stage of platform and construction of smaller parts on topside.

Fire, is a common hazard which could break out in all areas, could also occur in deep marine conditions. Fire could occur due to the presence of three components which are heat, fuel, and oxygen; therefore, fire could be prevented by separating or insulating each of these components. Fuels used on deep marine condition could be painting liquids, LPG, fuels for machines, and others.

Accident in Deepwater Platform

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The presence of too many equipment’s, tools, machines, raw materials, structural parts, and the limitation of space on the platform, work and transportation barges, could create an entrapment for the worker. In such a scenario, a situation involving fire / gas release or explosion could prove fatal. Hence, design engineers should be careful Offshore World | 16 | AUGUST - SEPTEMBER 2013

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>> Safety integration is the provision in a design to provide risk control of hazards. The designer who designs the layout of a particular platform has to consider these hazards. In addition, computerised control room, CCTV control centre and storage tanks with flammable fluid are also situated in the process areas to minimise hazardous.

Safety integration is the provision in a design to provide risk control of hazards.

In an ideal condition, hazards could be minimized by a design in accordance with the hierarchy. In a particular condition, for instance, in offshore industry which deals with petroleum (flammable) materials, fire and explosion could not be avoided, but risk of fire and explosion will be specific to a particular area of a platform. The designer who designs the layout of a particular platform has to consider these hazards. In addition, computerised control room, CCTV control centre and storage tanks with flammable fluid could also be situated far away from process areas. Since the control room has to be situated close to high risk areas, the designer could design fire and blast proof control rooms.

It could also be equipped with suitable hazard control devices.

Safety Culture It has been widely known that people could not be changed and that therefore the work conditions have to be changed accordingly. However, there is still a possibility to engineer systems that could reduce the risk of human error and experience has shown that this is not enough. Worker’s attitude has to be changed. A safety culture has to be created. All stakeholders involved in deep marine industry have to establish controlled safety policies. Those include, Oil Company as the operator of the offshore field, consulting firm which designs everything and contractors who install the infrastructure. Safety policies for each those parties could be different; therefore, a meeting / coordination need to be held before the project commences.

Heavy Lifting Operation in Deepwater

during carrying out designing process of these platforms and design a proper layout for positioning all areas involved during installation or operation phase of a platform.

Weather Conditions Sometimes due to bad weather, workers have to leave their work incomplete.

This condition leads to a potential hazard. For example, jobs for constructing scaffolding in rehabilitation work at topside area. A Scaffolder has to put specific tag on his incomplete job when he has to leave his work site. The tag could be a sign that the scaffolding structure could not be completed due to work stoppage.

On the following day, other workers will notice the tag on the scaffolding and carry out work activities accordingly Safety Integration Knowing or identifying hazards have already been presented in this article.

This section mainly discusses how to deal with the resulting risks. Which are: 1. Alter designs to avoid a hazard; 2. Provide facilities to reduce risk from a hazard by design; 3. Develop procedures to protect exposed persons; 4. Provide means for personnel protection.

Conclusion Working in deep marine condition involves a lot of things to be considered, especially the aspect of safety. Enforcement of safety in deep marine condition has to be started from the project design phase, installation or construction and during the operation stage. First thing that has to be performed is identifying the hazards and risks. Once the possible hazards and risks have been identified, the next action that needs to be performed is to establish safety integration among the stakeholders of the project. It could be done by reinforcing safety culture and establishing safety policies. sw

Dr Zafar Khan Deputy General Manager – HSE Leighton Welspun Contractors Pvt Ltd E-mail: Zafar.Khan@lwin.co.in

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features Water Treatment

Decontamination & Disposal of High Level Heavy Metals Waste Hydraulic fracturing process can require up to millions of gallons of water per well. Additionally, oil and gas wells can also produce significant quantities of produced/formation water. The produced water can contain substantial concentrations of elements, such as barium, strontium, calcium, magnesium, and chloride, etc. To reuse produced water for the purpose of fracturing, treatment of produced water to remove these elements is necessary. This paper discusses adsorption of water containing barium and strontium ions using bentonite and activated carbon as an adsorbent.

Produced water is a secondary product that oil and gas producers worldwide must address, both onshore and offshore. As part of the extraction process of recovering oil and gas from the reservoir, water is produced as a secondary product. On average, per barrel of oil produced in the world, approximately nine barrels of produced water will be pumped to the surface. This water must be handled and properly disposed. Produced water can contain water from the reservoir that has been injected into formation and can contain high amounts of heavy metals and different minerals 1 . The most commonly found scales within the oil industry are the carbonate and sulfate salts of calcium, barium, and strontium, which can be encountered from the reservoir all the way to the surface processing equipment 2,3. Barium sulphate and strontium scale formation are often, noted, mainly in the tubing of producing wells, where this scale can seriously jeopardize oil production. The primary cause of sulfate scaling is the mixing of incompatible waters, such as sea water and formation water, for example 4,5 . The water requirements on a wellsite for injection or hydraulic fracturing are quite large, increasing daily. Additionally, it is often difficult to obtain fresh water. Presently, most research is focused on use of produced water by removing contaminants and reuse of the same water for fracturing purpose.

Removal of heavy metals from aqueous solutions can be achieved using different technological methods. These methods include chemical precipitation, ion exchange, membrane filtration, electro-deposition, and flotation. Some of these methods have disadvantages and limitations. Precipitation, for example, produces large amounts of sludge in solutions 6; but, membrane filtration, ion exchange, electro-deposition, and filtration are costly 7,8,9. Alternatively, adsorption can remove these metals efficiently at low cost 10,11,12. Several solid materials can be employed as adsorbents. Activated carbon is considered an effective adsorbent because of its extensive porosity and large available surface area 13,14. On account of higher surface area, cation exchange capacity, and adsorption affinity for organic and inorganic ions, bentonite (mainly montmorillonite) is the most promising candidate for use in decontamination and disposal of high-level heavy www.oswindia.com

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metal wastes 15,16. In the discussed study, adsorption of Ba and Sr ions were carried out on the activated carbon and bentonite. Surface area of both adsorbents was largely responsible for the adsorption of both the metals.

Materials and Methods Instrumentation Elemental concentration was analyzed using a Thermo Inductively Coupled Plasma (ICP) optical emission spectrometer coupled with peristaltic pump and AS-93 plus auto sampler unit.

Chemicals Ba and Sr standard were used in this study. The pH adjustments were carried out using 0.1N hydrochloric acid (HCl) and 0.1N sodium hydroxide (NaOH). All Ba and Sr solutions were prepared with ultra-pure water (specific resistivity of 18 M Ω. cm).

Adsorbent The commercial bentonite (NB) was obtained from a local supplier; activated carbon was also obtained from a local supplier. To enhance the adsorption capacity of the commercial bentonite material, a 50-g sample was washed several times with deionized water to remove any particles adhering to the surface, salt, and any other water-soluble contamination; it was then was oven-dried overnight at 60°C under vacuum. The dried bentonite sample was then ground and sieved.

General Procedure Adsorption of Ba and Sr with bentonite and activated carbon was carried out in a conical flask. 1000 mg/L Ba and Sr standard was stock solution; Ba and Sr solutions ranging between 10 and 100 mg/L were prepared by diluting the discussed stock solutions.

0.5 Gm of bentonite mixed with 50 mL of Ba (II) and Sr (II) solution with different concentrations (10 to 100 mg /L) were applied in the stirrer. A 200-rev/min stirring rate and 298K temperature in all experiments were chosen. The flasks were then kept in a constant temperature bath with stirring. After 6 hr when equilibrium was attained, the

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concentration of Ba (II) and Sr (II) remained in the solution. After being centrifuged, the concentration was analyzed by an ICP spectrometer. In this study, the effects of several factors, such as pH, temperature, concentration of bentonite, and activated carbon were tested.

Adsorption Isotherms From the discussed batch adsorption experiments, the adsorbed amount (qe) of Ba and Sr (II) per unit of sorbent mass was calculated as follows: qe=(Co-Ce)V/M

(1)

Figure 1: Effect of adsorbent concentration on the adsorption of Ba and Sr.

Where Co is the initial Ba and Sr concentration, Ce is the concentration of Ba and Sr at equilibrium (mg/L), m is the clay mass (mg), and V is the solution volume (L).

Effect of pH The influence of pH in the range of 2.5 to 12 was studied, keeping all other parameters constant (Ba and Sr concentration = 10 to 100 mg/L; stirring speed = 200 rev/ min; contact time = 6 hr, adsorbent concentration = 0.5 g, temp. = 25째C). The pH of Ba and Sr solution was adjusted after adding the adsorbent by using a dilute of NaOH and HCl solutions. After equilibration (6 hr), samples were withdrawn for the analysis of Ba and Sr.

Bentonite

Activated Carbon

Qmax (moles/kg) K (dm /mol)

Qmax (moles/kg) K (dm 3/mol)

303

0.066

12579

0.074

2187.097

320

0.071

7040

0.103

1903.922

333

0.079

6023

0.192

1736.667

3

Table 1: Ba Adsorption on Bentonite and Activated Carbon

different bentonite concentrations (0.1, 0.3, and 0.5 g/50 mL, respectively.)

The results showed that, with increasing the adsorbent concentration, the adsorption % of Ba and Sr (II) were increased (Figure 1). The increase to the adsorption percentage of Ba and Sr with bentonite and activated carbon concentrations can be explained by the increase to the adsorbent surface area and the availability of more adsorption sites 17 . An increased surface area provides more sites to adsorb Ba and Sr on the surface of adsorbents. Figure 1 shows at 0.1 gm, adsorbent adsorption of Ba is 5 mg/gm, and that, of 0.5 gm, it is 14 mg/gm of adsorbent. In the case of Sr, also at 0.1gm, adsorbent adsorption of Ba is 3 mg/gm, and increased to 9 mg/gm if the adsorbent amount is increased to 0.5 gm.

Effect of pH The pH of the aqueous solution is an important variable that controls cationic adsorption onto adsorbent surface. This is attributed to the change of adsorbent surface properties and the metal species with pH change. The plots of adsorbed amount versus pH of Ba and Sr (Figures 2 and 3) have inflection points at pH 8 where significant adsorption of Ba and Sr actually begins. With an increase of pH of the solution from 2.5 to 12.0, Ba adsorption increases from 6 mg/gm of activated carbon to 30 mg/gm, and Sr adsorption increases from 5 mg/gm of activated carbon to 22 mg/gm. Ba adsorption on bentonite increases from 7 to 21 mg/gm, and Sr from 3 to 20 mg/gm when pH increased from 2.5 to 12. It is known that the increase of pH decreases the competition between the protons and the metal ions for surface sites and results in increased uptake of metal ions by the bentonite. The effect of pH on the adsorption of Ba and

Effect of Temperature Effect of three different temperatures (303, 320, and 333K) on the adsorption of Ba and Sr were also checked in a temperature bath. After attaining the respective temperature, adsorption studies were carried out in stirring conditions.

Effect of Adsorbent Concentration The adsorption efficiency of Ba and Sr was studied at different adsorbent concentrations [0.1to 0.5 gm/50 mL Ba and Sr solution] at Ba and Sr solutions (10 and 100 mg/L), keeping stirring speed (200 rev/min), temperature (25째C) and contact time (6 hr) constant.

Results and Discussion Effect of Adsorbent Concentration: Bentonite and Activated Carbon Adsorption of Ba and Sr (II) on bentonite and activated carbon was studied at

Figure 2: Effect of pH (activated carbon) on the adsorption of Ba and Sr.

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Bentonite

Activated Carbon

Qmax (moles/kg)

K (dm /mol)

Qmax (moles/kg) K (dm 3/mol)

303

0.024

6798

0.065

1562

320

0.034

6471

0.083

1479

333

0.05

3494

0.102

1066

3

Table 2: Sr Adsorption on Bentonite and Activated Carbon

Sr on bentonite can be explained on the basis of aqua complex formation of the oxides present in the bentonite. A positive charge develops on the surface of the oxides of bentonite in an acidic medium as follows: -------Si -----OH + (2) -------SiOH + H + A lowering of Ba and Sr adsorption at low pH is caused by surface charge, thus developed is not suitable for Ba and Sr adsorption. At low pH values, the high hydrogen ion concentration at the interface (the hydrogen ions are more specifically adsorbed than Ba and Sr ions) repels the positively charged metal ions electrostatically and prevents their approach to the adsorbent surface 18.

In an alkaline medium, the oxide surface of the adsorbent becomes negatively charged, as shown in Equations (3) and (4), favoring the adsorption of Ba and Sr. ---SiOH+OH −

---- SiO −+H2O

(3)

---SiO −+M ---Si---O---M (4) Increasing pH was reported to increase the adsorption of metal ions from kaolinite suspensions 19. Gutierrez and Fuentes 20 studied the adsorption behavior of Sr, Cs, and Co by Ca-montmorillonite, and showed that Co adsorption increases above the pH of

Figure 4: Langmuir adsorption isotherm for Ba on bentonite at different temperatures.

Ba

Sr

Parameter

Activated Carbon Bentonite Activated Carbon Bentonite

∆H(kJmol-1)

1.54

5.01

1.40

2.87

∆S(kJmol-1K-1)

0.010

0.0020

0.0055

0.004

∆G(k/mol-1) 303

-4.6

-5.6

-4.4

-5.2

320

-4.7

-5.6

-4.6

-5.5

333

-4.9

-5.7

-4.5

-5.3

Table 3: Thermodynamic Parameters for the Adsorption of Ba and Sr

precipitation of Co (OH)2. Mekhemer21 showed the precipitation of Co(OH)2 has been observed during the adsorption experiment; therefore, the drastic increase in cobalt removal above pH = 6 was attributed to the precipitation of cobalt ions as insoluble Co(OH)2, rather than the adsorption on the negative surface charges of bentonite. In the present study, no precipitation was observed at higher pH; adsorption increases when pH is increased.

Adsorption Isotherm Batch equilibrium studies of Ba and Sr with the adsorbents were conducted at different temperatures. The adsorption capacity of the adsorbents can be empirically correlated by Langmuir type isotherm. Initial adsorption data (i.e., q [Ba and Sr adsorbed amount moles/kg] and C [equilibrium concentration moles/dm 3]) were used to plot a 1/q vs 1/c plot, which is a linear line. From the linear line slope, intercepts were calculated. Q max and K were calculated by using slope and intercept, as shown in Equations (5) and (6).

Q max= 1/ intercept K= 1/ (slope*q max)

(5) (6)

The values obtained q max and K were used to calculate the q predicted. Equation (7) was used to calculate the q predicted.

Figure 3: Effect of pH (bentonite) on the adsorption of Ba and Sr.

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Figure 5: Langmuir adsorption isotherm for Ba on activated carbon at different temperatures.

Figure 7: Langmuir adsorption isotherm for Sr on activated carbon.

ΔG = -RT ln KL

Figure 6: Langmuir adsorption isotherm for Sr on bentonite.

Where q is the loading of the adsorbents expressed as moles of Ba and Sr adsorbed per kg of adsorbent, q max is maximum loading capacity, K is the equilibrium constant and is a quantitative measure of interaction between the Ba and Sr and adsorbents, and C is equilibrium concentration moles/dm 3. The lines shown in Figures 4 and 5 are the curve obtained by fitting the experimental Ba adsorption data on bentonite and activated carbon, respectively, into Langmuir adsorption isotherm at three different temperatures (i.e., at 303, 320, and 333 K). It was observed that, by increasing the temperature, the adsorption of Ba increased, indicating that the heat of adsorption was positive (endothermic). Q max for Ba on bentonite and activated carbon was 0.079 and 0.192 moles/kg, respectively (Table 1). Sr adsorption was also increased as the temperature increased. At 303K, qmax for Sr was 0.024 moles/kg, and increased to 0.05 moles/kg at 33K. Maximum loading capacity (i.e., q max for Sr) on bentonite and activated carbon was 0.050 and 0.1 moles/kg respectively at 333K (Table 2 and Figures 6 and 7).

Adsorption Thermodynamics The thermodynamic parameters of the adsorption (i.e., the standard enthalpy ΔH°), Gibbs free energy ΔG° and entropy ΔS° were calculated using the following equations:

(6)

ln KL = ΔS/ R – ΔH /RT (7) Where R is the general gas constant (kJ .mol−1. K−1), KL = Langmuir adsorption constant and T is the temperature (K). ΔH° and ΔS° values can be obtained from the slope and intercept of the Van’t Hoff plots of ln KL (from the Langmuir isotherm) versus 1/T22,23. The results of these thermodynamic calculations are shown in Table 3. The negative value for the Gibbs free energy for Ba and Sr (II) adsorption shows that the adsorption process is spontaneous and that the degree of spontaneity of the reaction increases with increasing temperature. The overall adsorption process of Ba and Sr is endothermic (activated carbon: Ba, ΔH = 1.53 kJ mol−1, Sr ΔH = 1.39 kJ mol−1 and bentonite: Ba, ΔH = 5.01 kJ mol−1, Sr ΔH = 2.87 kJ mol−1). This result explains why the Ba and Sr (II) adsorption capacity of bentonite and activated carbon increases with increasing temperature. Table 3 also shows that the ΔS value was positive, indicating that the metal ions near the surface of the adsorbent was more ordered than in the subsequent adsorbed. sw (For ‘references’, please log onto www.oswindia.com)

Anil R Patil Senior Scientist – Analytical Chemistry Halliburton Technology Center – Pune E-mail: Anil.Patil@Halliburton.com Jajati Nanda Senior Scientist – Analytical Chemistry Halliburton Technology Center – Pune E-mail: JaJati.Nanda@Halliburton.com Omprakash Pal Principal Scientist – Analytical Chemistry Halliburton Technology Center – Pune E-mail: Omprakash.Pal@Halliburton.com

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interview

‘We aim for projects worth USD 1 bn’ Two years back, EPL split the company into six SBUs with the clear cut objective to unlock the value and true business potential across the boundaries. EPL’s Hydrocarbon SBU’s current order book stands at around USD 4.1 billion. Amit Gupta, CEO, EPL - Hydrocarbon SBU has set the target to reach USD 1 billion during the current fiscal with USD 500 million coming in from the Indian market. He talks about the EPL’s overseas growth strategy which has catapulted EPL’s growth and more in an exclusive interview with Mittravinda Ranjan. Excerpts...

Amit Gupta, CEO - Hydrocarbon SBU Essar Projects Ltd

What was the rationale behind carving out Hydrocarbon business as a Special Business Unit?

In 2011, EPL split the company into six SBUs with a clearcut objective to start working independently as stand-alone businesses. The company is now structured in a way that makes it possible for us to independently bid for projects in these segments. The creation of Hydrocarbon SBU was to lead greater focus, empowerment, transparency, stronger leadership and increased competitiveness thus unlocking the value and true potential of the hydrocarbon business.

EPL’s current order book is around USD 4.1 billion and Hydrocarbon SBU is out to target an order book around USD 1 billion.

EPL is gaining strong foothold in the Middle East.

How important is this market in your inorganic growth strategy?

Middle East has always been our radar especially in the hydrocarbon space despite facing the stiff competition from the South Koreans, existing local contractors & well-established Indian players in the region.

Today the total order book of all our contracts put together in Abu Dhabi is around USD 170 million, which is perfectly in line with our Middle East entry plan and a testimony to our business development efforts aptly www.oswindia.com

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backed by aggressive pricing model approach of our estimation team.

We are also in process to tap the markets in Sultanate of Oman and Kingdom of Saudi Arabia as well. With some big contracts still to be awarded, we do feel that there is scope for the firm to go on to even greater success but the key to our strategic presence in the region lies in successful and timely execution of these projects.

How do you compare Middle-East market with South-East Asia or African market in hydrocarbon space?

Middle-East is a mature market as well as the clients are well spell down of their requirements. The project duration and the timeline in Middle-East are much more realistic vis-à-vis African market. Although African market is now open to international players coming in, there is scepticism among the policy makers who are more keen on utilising resources within their countries for development rather than taken away to other markets.

Their policy and the procedures are still at a nascent stage and require some time to attain maturity. EPL is now concentrating more in the African market, because Middle East is also getting saturated and we are confident that this move will certainly help us to increase our international footprint.

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How do you compare the qualification criteria & bidding processes of Engineering, Procurement and Construction (EPC) model internationally with the Indian market?

Presence in the local market is one of the key qualification criteria to qualify for bidding for projects in the Middle East market but the fact remains that most of the national oil & gas companies in the Middle East and North Africa (MENA) region are conservative by nature, gaining their trust takes time.

We have set up local offices in Abu Dabhi, Sultanate of Oman, Kingdom of Saudi Arabia , Kuwait and Qatar with the aim to provide a base for new business development teams in the respective regions to register ourselves within the countries to explore new opportunities.

But the Indian market is still not very open to the EPC mode of project execution and most of the projects are still executed in the conventional mode, where engineering is separated from procurement & construction.

What are the challenges that you foresee during the execution of international projects and how are you gearing up for the same?

Initial manpower and equipment mobilisation are the most critical challenges we envisage for timely project execution. We have been facing initial teething problems on getting the work visas, work permits and the right mix of site personnel for successful execution of these projects.

During the execution phase, it is essential to deploy personnel with overseas experience, be precise in crucial decisions and move forward to actualise the plans rather than spend excessive time in exploring alternatives or going into Research and Development (R&D)since the EPC projects have predefined boundaries of time, cost quality and critical parameters regarding the plant performance.

However, with careful planning through all phases of the projects, we are confident about executing the projects within the stipulated time frame and budget.

>> We have set up local offices in Abu Dabhi, Sultanate of Oman, Kingdom of Saudi Arabia , Kuwait and Qatar with the aim to provide a base for new business development teams in the respective regions to register ourselves within the countries to explore new opportunities.

How is EPL consolidating its presence in the Indian market?

Initially, we were more focused on developing internal projects but we strengthened our competencies aimed at bringing paradigm shift from catering in-house projects to external clients in India and gaining significant overseas presence. We won the contract for the Engineering, Procurement & Construction (EPC) of the Reactor Regenerator package of 2.2 MMPTA Fluid Catalytic Cracking Unit (FCCU) at the Kochi refinery, which is set to expand to 15.5 MMPTA. We also won the largest single EPC package of the Coke Drum Structural package (CDSP) for the Kochi Refinery again. Last year, we bagged the EPC package for process units of Indian Oil Corporation Limited’s (IOCL) Paradip refinery project – 15 MMPTA grass root refinery project. Yes, we do hope that these awards will certainly consolidate our position in the Indian hydrocarbons sector and position EPL as a leading EPC contractor in near future in the field of hydrocarbons in Indian and international markets.

What are the other projects in EPL’s USD 4.1 billion kitty presently and what is the size of order book for the oil & gas projects?

Our international projects include USD 400 million Outside Battery Limit (OSBL) works at Jurong Aromatics Complex in Singapore for Jurong Aromatics Corporation (JAC) and 9 process units on a LSTK basis for the 15 MMTPA refinery at Paradeep in Odisha for IOCL. Besides, we are also executing an EPC contract for Matix Fertilizers and Chemicals involving a 2,200 MT/day Ammonia plant (0.73 MMPTA) and 3,850 MT/day single-stream Urea plant (1.3 MTPA) along with associated utilities and offshore facilities.

We are executing contracts worth USD 170 million in Abu Dhabi for our overseas clients.

We have recently been awarded subcontracts worth USD 50 million to us – one by Samsung Engineering, Korea, which involves civil works for the Carbon Black & Delayed Coker (CBDC) Offshore World | 23 | AUGUST - SEPTEMBER 2013

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project for the Ruwais refinery and the other by G S Engineering.

We have three key EPC projects in Abu Dabhi, which are at different stages of execution currently. First one is USD 30 million project by TAKREER involving EPC works, commissioning and start-up for the Spent Caustic Treatment Plant; second project is worth USD 35 million from Abu Dabhi Polymers Company Ltd (Borouge), which includes EPC of process equipment , associated pipelines and control systems for PE Color Grade Compounding (CGC) plant. The third project is the largest worth USD 55 million from Abu Dhabi Gas Industries Ltd (GASCO) involves Engineering, Procurement, Construction & Commissioning (EPCC) of condensate pipeline from Habshan to Ruwais - in Abu Dhabi. EPL has bagged these awards on direct basis thus marking our real presence in the Middle East market. We are targeting another USD 500 million contracts in India in the current fiscal year.

What kind of opportunities do you foresee in the hydrocarbon sector in this scanty situation?

The growing energy demand in the domestic market creates immense opportunities for EPC players in the country, but the country is not able to capitalize on that on account of regulatory and bureaucratic hurdles. India’s LNG regasification capacity is currently being expanded and new LNG projects are expected in the near future thus enhancing investment opportunities in the country.

Petronet LNG is coming up with a new terminal in Gangavaram, Andhra Pradesh and also planning to expand its existing terminal in Dahej, Gujarat. Indian Oil Corporation Limited (IOCL) is planning a new terminal in Ennore, Tamil Nadu while GAIL (India) is looking to expand its existing terminal in Dabhol, Maharashtra. Oil and natural gas major ONGC has finalised a surface facility revamp programme for its three onshore assets Ankleshwar, Ahemedabad and Mehsana. www.oswindia.com

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Gujarat State Petronet Limited (GSPL) has planned out a huge network of pipeline almost 5000 km. in consortium along with state-owned IOCL, BPCL and HPCL has received a nod from Petroleum and Natural Gas Regulatory Board (PNGRB) to lay down three cross-country gas pipelines namely Mallavaram-Bhilwara (1611 km), MehsanaBhatinda (1688 km) and Bhatinda-Jammu (512 km) pipeline having initial capacity to carry around 95 mmscfd of gas.

limited number of projects. The actual number of projects available in India is not sufficient enough to fully utilise the established capacities of all the EPC providers.

These developments would facilitate the development of pipeline networks leading to the evolution of the much awaited National Gas Grid, which is critical for the country’s energy Security. Although there is a huge potential already available in the Indian market, but the only problem is all the projects are gas or power driven for which the entire infrastructure is not available within the country. Most of the planned LNG projects, gas pipelines and refinery projects are getting delayed due to same clearances issues and bureaucratic hurdles and as a part of EPL’s growth strategy,

However, it is expected that the government will initiate further changes to policies and subsidy schemes in attracting the future investments in critical industrial areas.

The Petroleum Minister has recently announced that India has 65 per cent unlocked oil & gas reserves potential. What potential do you foresee for EPC providers in the years to come & the concurrent challenges?

As many oil & gas majors are venturing into Greenfield and Brownfield expansion projects, expansions of refineries and their integration with downstream petrochemicals, LNG regasification terminals and petcoke gasification are leading the investments which is a positive sign for the EPC industry.

Further, delay in clearances, indicators, policy uncertainties of financing lead to the delay implementation add to the EPC contractors.

weak economic and high cost of the projects woes of the

Off-late, it is noticed that due to the entry of several EPC players, the bidding process of the projects has become very aggressive and the projects are awarded at very low cost, sometimes even way below the clients’ budget.

These unworkable costs areas lead to severe constraints for resource mobilisation and ultimately impact the project schedules and quality. The present scenario calls for the need of fair contractors and an in-depth analysis of how the stakeholders viz. project owners (clients), the PMCs and the EPC contractors respond and what are the possible strategies to deal with prevailing risks during project development and execution.

achievement of 100 per cent coverage of unexplored basins in a time-bound manner to enhance domestic availability of oil & gas.

We need to secure acreages in identified countries having high attractiveness for ensuring sustainable long-term supplies. We need to pursue projects to meet the deficit in demand and supply of natural gas, and facilitate availability of LNG. Additional creation of infrastructure for distribution and marketing of oil & gas is the need of the hour.

Also there is a need to open up the hydrocarbon market so that there is free and fair competition between public sector enterprises, private companies and other international players.

Having a rational tariff and pricing policy would ensure the consumer getting the petroleum products at the most reasonable prices and requisite quality, eliminating adulteration.

Unconventional hydrocarbons can play a big role in securing India’s energy security. These are new areas and therefore have to be carefully nurtured.

Shale gas can become a major source of energy, provided these assets are developed to their full potential.

Also most of the EPC contracts are tilted more in favour of the project owners, which is a major drawback. There is a need to have fair contracts which could give a breather to the EPC contractors as well.

However, for these to be tapped and used, pipelines should be developed. Shale gas production peaks initially and therefore before any major development of shale resources, pipelines should be planned and put in place in advance of production.

What changes would you like to see in Govt’s policy on Hydrocarbon sector? What measures do you suggest for the same?

Govt needs to focus on oil security through intensification of exploration effor ts and

The unconventional hydrocarbon resource CBM (Coal Bed Methane) can play a complimentary role in meeting energy needs of India. CBM availability is marginal as of now, compared with the total energy demand in the country.

>>EPC players continue facing the challenge in the Indian market which is an open truth and the industrial scenario is not very much in favour for larger EPC services providers due to various reasons, foremost being availability of limited number of projects. The actual number of projects available in India is not sufficient enough to fully utilize the established capacities of all the EPC providers.

The hydrocarbon sector plays vital role in the economic growth of the country, contributes to the country’s gross domestic product (GDP).

Hence it is necessary to have a long-term policy for the hydrocarbons sector, which would facilitate sw meeting the future needs of the country.

However, EPC players continue facing the challenge in the Indian market, which is an open truth and the industrial scenario is not very much in favour for larger EPC services providers due to various reasons, foremost being availability of

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interview

‘India can not afford to lose 4 per cent of GDP to corrosion’ Demand for stainless steel for the entire Hydrocarbon spectrum, ranging from onshore to offshore, has been growing as requirements on high-end materials of construction used in hydrocarbon exploration and processing are increasing. Yatinder Pal Singh Suri, Country Head, Outokumpu India Pvt Ltd, details about the manifold applications for stainless steels and high performance alloys across the whole hydrocarbon value chain with an exclusive talk with Offshore World.

Yatinder Pal Singh Suri Country Head Outokumpu India Pvt Ltd

How has the demand of new materials of construction changed across the entire hydrocarbon value chain?

What are the core strengths of Outokumpu in terms of services for the entire Hydrocarbon spectrum?

There are manifold applications for stainless steels and high performance alloys across the whole hydrocarbon value chain: • From oil & gas upstream applications such as well head equipment, X-mas trees, wire lines, flexible and rigid pipes, long products for drilling applications, hanger and packer.

• Over topside application areas – blast & fire walls, structural components, cable trays, stairs, tread plates, pipe supports, process piping, oil & gas coolers, heat exchanger units, manifolds, seawater systems, etc.

• To onshore applications such as storage tanks, refinery heat exchangers and coolers, burners, chimneys and flaring systems, distillation columns and internals, either as solid solution or cladded / overlay welded.

This is continued in the process industry where our alloys are used for any kind of process equipment such as vessels and pressure vessels, reactors, columns, tanks, tubes

and pipes, fittings and flanges, heat exchangers, filters, centrifuges, pumps.

The demand for high performance stainless steels and high performance alloys in these applications is growing as requirements on materials used in hydrocarbon exploration and processing are increasing: • Oil reserves in our oceans are deeper and deeper going along with increasing demands on mechanical properties in combination with corrosion resistance.

• Life cycle cost considerations and finding sustainable solutions are drivers for our development in high strength in duplex and lean duplex sales which offer very competitive solutions in comparison to standard stainless steel or coated carbon steel solutions.

• Our high performance stainless steels and our high performance alloys such as nickel base alloys, titanium and zirconium are coping with harshest demands in terms of corrosion resistance in most demanding downstream processing operations.

• Improving the efficiency of chemical process usually goes along with increasing process temperatures, this is where our heat resistant steels and alloys come in.

>>Being the oldest and largest stainless steel player in the world, Outokumpu has positioned itself as the wise stainless men who are educating the domestic end-users on new grades and applications and also giving new opportunities to the domestic mills to learn from us and upgrade their capabilities.

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of high-end grades for oil & gas applications with successful track record of reliable performance in various projects abroad. In fact, we would fit into the scheme very well since the EPC company will not face problems either on product knowledge and availability or any adverse forex effect since export projects involve buying and selling in foreign currency.

Outokumpu Stainless Ltd, Sheffield, UK

What is the total stainless steel demand in India and how is Outokumpu positioned in the market against the competition especially from the domestic players?

There are over 400 grades of stainless steel which can be used for the diverse range of applications depending on the operational environment. In India, the dominant demand comes from the utensils and kitchenware application segment which is as high as 65 per cent. This is the lowend application being catered to by over three dozen induction melting route manufacturing units as well as the four integrated manufacturing plants. Outokumpu is not catering to these segments.

The industrial and infrastructure applications constitute 35 per cent of the overall demand (around 700,000 tonnes per annum). Since the range of production capability of domestic integrated plants is rather limited at this point of time, imports are vital to meet demand for high-end advanced materials for the accelerated infrastructure growth. Outokumpu presence in India is primarily relevant for the high-end grades and higher dimensions.

Being the oldest and largest stainless steel player in the world, we have positioned ourselves as the www.oswindia.com

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wise stainless men who are educating the domestic end-users on new grades and applications and also giving new opportunities to the domestic mills to learn from us and upgrade their capabilities.

Post-acquisition of Inoxum, what kinds of opportunities are available for Outokumpu globally & in India?

Outokumpu and Inoxum are highly complementing – Outokumpu having been a leader in high performance stainless steels and running the most efficient mill for austenitic standard grades is now complemented by Inoxum’s strong position in ferritic, martensitics, and high-quality surface finishes for different applications such as architectural or white goods. We now have the full range of high performance stainless steel and alloys.

The new Outokumpu is the global leader in advanced materials. We are helping the world to reduce the pace of consumption of our planet and thus make the world last forever.

What kind of future do you see for Outokumpu in India when many EPC companies are now looking at the Middle East & other international markets for oil & gas?

For projects abroad, Outokumpu can be an ideal partner due to our global presence, a wide range

Please apprise us of Outokumpu’s association with German pipe manufacturer in supplying Natural gas pipe for the dock loading facility in Port of Ras Laffan in Qatar? (Please comment on how Duplex Steel has replaced the conventional MOC and how has the gas company benefited from this) Pipes in duplex are used for gas transportation but not for LNG. The benefits by using duplex are: • Higher corrosion resistance than carbon steel (both uncoated and coated).

• Higher strength than standard austenitic grades and carbon steel • Thinner gauges • Less weight • Less welding consumables • Withstand higher pressures (if not down gauging) • Lower price volatility As the E&P activities are moving towards difficult areas, what kind of opportunities do you see for yourself in India?

Corrosion is a serious issue in the oil and gas sector and the consequences of corrosion failures are going to be more and more unaffordable as we go forward into the future. As a developing nation which is resource crunched, we can not afford to lose 4 per cent of our GDP to corrosion.

In India, historically, there has been a tendency to keep the initial investment at lower levels.

Through this approach, we are willingly sacrificing the life-cycle cost advantages which can be accrued through proper material selection to achieve much longer maintenance free life of the investments made.

Life-cycle cost is a well understood and known concept to the designers and consultants and there will be enhanced pressure to go for high-end products to keep the plants running uninterrupted

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for a long time. As we go to sub sea applications, the cost of repair and maintenance can be ten times the cost of initial investment. Thus there is a big opportunity for Outokumpu to educate the EPC sector participants about the life-cycle cost advantages through advanced materials and support them in creating investments with higher productivity and lower life cycle cost structure.

Please apprise us of Outokumpu’s technical application in Subsea drilling since it’s ever deeper and even greater demands will be placed on the materials used for the unit in minimizing overall lifecycle cost?

As already explained earlier in first question, we reiterate that as oil reserves in our oceans are going deeper, there is a high focus on robustness in design and material selection. The deep waters have more challenging environments with increased temperatures and pressures. As Outokumpu has a very wide product portfolio including advanced materials we can offer the most optimal solution for almost all kind of applications.

May we have your comments on the risks and challenges associated with working in India at present due to brief hiatus on implementation of projects and how are you mitigating the risks?

India is definitely not a preferred destination for investments due to a variety of policy gaps and multiplicity and uncertainity of clearance procedures. There are project cost escalations due to delays in project implementation leading to many conflicts and defaults in contractual obligations across the supply chain. We have been supporting many budgetary enquiries for various important projects but the take off is so slow.

We feel that the risks are minimum for Outokumpu since we follow the partnership approach by being honest and transparent in our dealings

from a budgetary enquiry level to final order and supplies. By offering reliable services even during the tough times of a customer, we aim to earn the trust for the long term. It is tough but mutual trust pays ultimately.

Domestic stainless steel production has been on an upward swing during the last quarter and some of the steel have already planned indigenous capacity expansions.

Further with an antidumping duty that is imposed on steel imports, how do you plan positioning yourself strongly in the Indian market?

There is overcapacity in the domestic sector in the low-end and vanilla grades of stainless steel.

Since stainless steel is the fastest growing metal in consumption (about 10 per cent annual growth in India), it is hoped that the over capacity will get filled up in the next four years. This means the fixed cost element for the new plants is high due to low capacity utilization. There is a tendency to drop prices to chase a demand which is much smaller than the supply and this downward spiral hurts everyone in the long run.

Since landed steel is dollar denominated, what impact has the depreciation of rupee made on the imports? How do you intend to further curb this challenge as the analysts have predicted further slide in the rupee value?

The devaluation impact currently is definitely beneficial to domestic players providing them with an opportunity to improve their domestic selling prices and also a greater opportunity in export markets.

dumping duties despite the 40 per cent advantage is not a strategy since it hurts the downstream segments badly.

What is the kind of challenge you see from the EPC companies with integrated steel capacities in terms of opportunities and market penetration?

There is just one EPC company who has integrated stainless steel melting and forging capability.

We do not see any challenge there but see an opportunity to support them in manufacturing advanced materials so as to use their installed capacity profitably.

How do you plan to steer the growth of the company in India and scaling up the operations?

There are huge investments in pipeline for infrastructure which includes Energy, Oil & Gas, chemical process, storage tanks for oil and chemicals, Railways coaches, wagons and bridges, ports, water effluent treatment, desalination, storage and distribution of potable water, food processing and grain storage to name a few of critical areas.

Our extremely long coastal line adds yet another dimension to big challenges due to its corrosive environment. Tackling corrosion means using more high-end stainless steel grades and that is an opportunity for Outokumpu. It is the right time for Outokumpu to work together with local partners and make India stainless in line with our vision – A world that lasts forever!! sw

Unfortunately, despite the devaluation of rupee by over 40 per cent in past one year, the domestic players continue to indulge in downward spiral and make losses. The domestic players surely need to follow a pricing strategy to improve their bottom lines. Seeking higher import duties and anti

>> There are huge investments in pipeline for infrastructure which includes Energy, Oil & Gas, chemical process, storage tanks for oil and chemicals, etc in India. It is the right time for Outokumpu to work together with local partners and make India stainless in line with our vision – A world that lasts forever!!

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features Cyber Security

Industrial Security: An Integrated Approach With the sharp increase in cybercrimes today, process industries too are equally vulnerable to cyber-attacks and need to leverage technology to protect their assets, intellectual property and profitability. As control networks continue to expand and integrate to business systems, the risks and complexity of cyber vulnerabilities must be addressed with the same vigilance as process safety risks assessments.

What is a ‘smart plant’? For many, the concept of a smart plant involves the integration of critical process subsystems and instrumentation with the aim of streamlining operations, maximizing production and ultimately, increasing profits. However, the ultimate goal of a smart plant isn’t just to automate processes or capture knowledge electronically; it is to increase the operator’s awareness of the surrounding environment to help him/ her make the best decisions possible in the control room. Plant security – both cyber and physical – is becoming an important part of that environment.

The ability of operators to be aware of and respond to security incidents has become an invaluable skill that’s equally as important as knowing how to respond to a process upset. Just as a process upset can be disastrous, a security breach can produce equally devastating results ranging from lost production to lost lives.

It’s only natural, therefore, that a wide variety of security systems ranging from access control and video surveillance, right through to perimeter fences and IT security, have gradually been incorporated into the overall plant integration strategy.

In addition to keeping track of assets, an ideal solution will be able to: • Identify and control who enters and exits the plant • Track movement of facility occupants • Control access to restricted areas • Track and locate equipment, products and other resources • Track location of onsite personnel in the event of an incident • Protect process automation networks and systems from cyber threats • Respond proactively to alarms and events • Share data to generate costs savings Five Steps to Achieving an integrated plant security system To effectively secure a facility, plant managers must take an inside-out approach.

That is, they must start with securing the heart of their plants (the process control network) and gradually build layers of protection that extend all the way to the

>> To effectively secure a facility, plant managers must take an inside-out approach. That is, they must start with securing the heart of their plants (the process control network) and gradually build layers of protection that extend all the way to the property perimeter. www.oswindia.com

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property perimeter. Therefore, if one measure is breached, another is there to back it up. In order to achieve these layers of protection, there are five steps that should be followed: 1. A site vulnerability assessment 2. Understanding available security systems 3. Determining mitigation steps 4. System implementation 5. Reassessment Assessing the Vulnerability of a Site The first step in designing any kind of safety and security architecture is assessing the vulnerabilities being faced and understanding the risks that are created as a result. The ensuing strategies are dependent on the distinguishing characteristics of specific facilities and the business goals of the corporations that operate them.

The goal of a site vulnerability assessment (SVA) is to determine possible holes in a plant’s overall security system and prioritise improvement opportunities based on what is most critical. A typical SVA can take about a month to fully complete, depending on the level of detail and the size of a facility.

During the SVA, it’s critical to examine the relationships between site security and safety, as well as physical security and cyber security. A security breach represents a threat to plant safety so it’s important to consider the steps plant operations staff can take to reduce the impact.

The Importance of Cyber Security The SVA should not stop at physical security measures. It should establish a baseline of a company’s current cyber security processes, procedures and safeguards used to protect the process control network (PCN) from external threats.

The PCN is one of the most critical areas of any facility and it can also be one of the most vulnerable to the growing threat of cyber terrorism. Cyber threats can be classified in four categories: • Indiscriminant and potentially destructive – Probably the most common threat faced by industries and private users throughout the world, this category includes virus, Trojan horse and worm attacks.

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>> The goal of a site vulnerability assessment (SVA) is to determine possible holes in a plant’s overall security system and prioritise improvement opportunities based on what is most critical. A typical SVA can take about a month to fully complete, depending on the level of detail and the size of a facility.

•

•

•

P e r f o r m a n c e i m p a c t s a n d p o t e n t i a l s a f e t y i s s u e s –T h r e a t s such as network spoofing and “denial of ser vice” attacks can clog a PCN with spurious requests, preventing the operator from receiving a legitimate alarm.

Confidentialit y – Ano t her o f t he mo st -pu blic ised c yber threats is eavesdropping and password cracking which allows hackers to access confidential information such as business figures or recipe data.

Confidentiality, integrity, and performance – This area is especially dangerous if the intruder has malicious intent. It includes data tampering, impersonation and packet modification.

All of these categories have safety issues – if the system is compromised, so is safety. Keeping the PCN operating safely and without interruption, therefore, can prove challenging.

Just like physical security risks examined during an SVA, PCN vulnerabilities can be ranked based on their risk potential. These include poor password management, missing or out-of-date anti-virus software, missing OS security patches, and ineffective processes for communicating policies.

Determining Mitigation Steps After vulnerabilities are categorised and prioritised, mitigation steps must be identified. Mitigation steps are unique to each site, but there are many common best practices which have proven to enhance safety and security.

For example: • Multiple layers of protection so if any specific layer is compromised, there are other preventative measures still in place. This approach employs a variety of technical protection elements such as perimeter intrusion detection, access control, surveillance cameras and radar to monitor approaching vessels on the waterway.

• A linked security system and process control system which allows for efficient tracking of personnel. In the event of a security breach or safety hazard, process operators can use RFID, cameras and access card readers to determine where affected people are located.

Implementing the System Integrated systems allow plant operations staff to increase situational awareness and improve collaboration and responsiveness so as to reduce safety and security risks. In order to ensure the implementation process goes smoothly when integrating security and manufacturing systems, Distributed Server Architecture (DSA) should be employed.

One of the most important requirements in achieving integration is the ability to tie third-party systems together. Without a standard such as DSA, it’s virtually impossible to achieve effective communication that allows a site to be more aware of a security issue, and awareness allows for increased responsiveness. .DSA provides the communication mechanisms for sharing information across systems but also allows sites to be flexible in upgrade planning.

The Complex ROI Calculation Justifying the cost of something as complex as an integrated process control-security system is usually a mandate for plant managers.

Unfortunately, it’s also one of the hardest things to do because calculating return on investment isn’t straightforward.

One tangible to strive for is reduced risk, which can be verified through reassessments. In some cases, sites can obtain lower insurance rates if they can prove that they have substantially reduced safety and security risks. In this regard, Oil & Gas plants must ensure their systems keep pace with the ever-evolving security threats, and that their cyber and physical security systems are properly controlled.

Integrating process control and security systems will reduce risk more than independent systems as it allows for greater collaboration between security and process operations during an incident. More information being delivered in a timely way will help the site improve responsiveness.

This information sharing is what will truly serve the basis for a smart plant – one that is secure from the inside out. sw

Shawn Gold Global Program Manager, Honeywell Process Solutions

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features HSE Aspects

HSE Design Codes for Refineries & Petrochemicals While designing a Chemical plant, Health, Safety and Environment (HSE) aspects should be considered from start at the concept stage of the project which gets realised through all the stages such as design, construction, commissioning and most importantly during all modes of operations such as start-up, shut down, turndown etc.

The article describes a comprehensive HSE plan to achieve process safety in identifying hazards such as fire, explosion and accidental chemical release which could have serious effect on life, property & environment and to prevent/mitigate such hazards to reduce risk to an acceptable level.

Health, Safety and Environment (HSE) demand highest level of commitment while designing a Chemical plant. The objective of process safety is to identify hazards such as fire, explosion and accidental chemical release which could have serious effect on life, property and environment and to prevent/mitigate such hazards to reduce risk to an acceptable level.

Deliberation on this issue should start right at concept stage of the project which gets realised through all the stages such as design, construction, commissioning and most importantly during all modes of operations such as start-up, shut down, turndown etc.

The Safety Life Cycle covering various phases from initiation and specification of safety requirements, design and development of safety features in a safety-critical system and ending in decommissioning of that system is shown in Fig 1.

START EIA, PHA, HAZOP Risk Analysis, HAZID, SIL

Design Execute & Evaluate

START EIA, PHA, HAZOP Risk Analysis, HAZID, SIL Modifications & Management of Change

Figure 1: Safety Life Cycle

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Other HSE design aspects such as hazardous area classification, emergency power supply for safe shutdown, noise mapping and control etc. must also be considered at design stage.

HSE Studies and Reviews During the FEED and EPC phases of the project, the following design reviews are recommended as a minimum to ensure that HSE requirements are incorporated in design: Review Type

FEED Phase

EPC Phase

Environment Impact Assessment (EIA) study Before FEED phase Hazard Identification (HAZID)

X

X

Plot Plan Review

X

X X

Escape Route Study Hazardous Area Classification Review Erection, Commission & Validate

Operations & Maintenance

The first step towards achieving process safety objective is to formulate a comprehensive HSE plan covering the following key design aspects and activities: 1. HSE studies and reviews 2. Plant layout incorporating HSE requirements 3. Pressure relief and blow down system 4. Safety instrumented system 5. Fire and Gas detection system 6. Fire protection system

X

X

Fire and Gas Detection and Alarm Systems (F&GDAS) Safety Review HAZOP

X

X

X

SIL Assessment

X

Hazard Analysis (HAZAN)

X

Preliminary Quantitative Risk Assessment (QRA) X Detailed Quantitative Risk Assessment (QRA)

X

HSE Design Review

X

3D Model Pre Start-up Safety Review

X

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>> Other HSE design aspects such as hazardous area classification, emergency power supply for safe shutdown, noise mapping and control etc must also be considered at design stage.

HSE Aspects in Plant Layout Impact on environment and safety are the major concerns addressed while preparing Plant Layout. The site layout should aim to contain an accident at source to prevent escalation of events to other units.

OISD 118 provides recommendations for design of Plant layout for oil and gas installations. The safe distances indicated in OISD 118 should be treated as minimum. Whenever it is not possible to provide these minimum distances, other protection measures against fire and explosion need to be considered, for example installation of blast/fire walls.

The Design engineer must ensure maximum separation between flammable hydrocarbons and ignition sources is achieved. Off-site facilities should be located according to the prevailing wind direction. e.g.:

Pressure relief device such as safety valves are used as the primar y means of overpressure protection. The design of each pressure relief device is based on assessment of overpressure scenario such as blocked outlet, heat exchanger tube rupture, external fire, thermal expansion, power failure etc.

In addition to traditional pressure relief valves, de-pressuring systems can be used to mitigate the consequences of vessel leak by reducing the leakage rate and/or inventory prior to a potential vessel failure.

Depressurising ser ves to reduce the failure potential from scenarios such as overheating (fire), runaway reaction etc.

General emergency depressurisation of a plant area is activated using switches located in the control room and locally in the plant. The operator must ascertain that it is safe for depressurisation to be initiated.

Depressurisation rates shall be based on the requirements of API 521. The design of the depressurisation system shall comply with the requirements of OISD 106.

Cooling tower should be located downwind of process units.

Heaters should be located upwind of process unit.

Main administration building and fire stations should be located upwind of process, utility and storage areas.

Loading and unloading areas shall be located downwind or crosswind of process and utility areas.

Flares should be located downwind or crosswind to process and utility areas and remote from process, utility blocks and the administration area.

Safety Instrumented System (SIS): SIS ensures safe shutdown of the plant due to unexpected emergencies and hence reduce the potential for uncontrolled release of toxic and flammable material to atmosphere. It ensures that the process conditions i.e. pressure, level, temperature etc. are maintained within the design envelope. For example, SIS can isolate hydrocarbon entering or leaving plant equipment and facilities, remove heat input from process heaters, de-energize rotating equipment and permit manual depressurization of isolated lines and equipment.

Provisions should be made to ensure that all routine operations involving handling of materials and equipment are conducted in a safe manner. Layout should take into account access requirements in case of an emergency. All escape routes shall be readily accessible and unobstructed. Escape routes should be designed such that escape may be achieved under emergency conditions without risk of serious injury or loss of life.

SIS is a set of hardware and software which is engineered to bring the operating plant to fail safe position or maintain safe operation of the plant when a hazardous condition occurs. SIS is independent from all other normal control systems to ensure its functionality is not compromised during emergency.

• • • • •

Safety showers and eyewash units should be located in the layout wherever there is a risk of exposure of personnel to irritants that are toxic by absorption, material being handled at elevated temperatures or chemicals that can cause immediate or irreversible damage on contact with skin. Safety shower shall be designed as per IS 10592 or ANSI Z 358.1.

Pressure Relief and Safety Instrumented System Pressure Relief & Blowdown System : In the process industr y, an important safety consideration is the prevention of loss of containment due to vessel or pipeline overpressure situations. Loss of containment ca n re s u l t i n i m p a c t to h u m a n l i f e a n d t h e e nv i ro n m e nt, w h e n flammable, explosive, hazardous or toxic chemicals are released to atmosphere. API 520/521 and ASME provide criteria for design and protection of vessels and pipelines from rupture or damage caused by overpressure.

The functional requirements and reliability of SIS is determined from Hazard and operability studies (HAZOP), layers of protection analysis (LOPA), risk graphs etc. These techniques can be referred in IEC 61511 and IEC 61508.

OISD 152 gives recommendations on safety instrumentation for process system in Hydrocarbon industry.

R e m o te l y O p e rate d Va l ve s ( R OV ) : Th e p u rp o s e o f R e m o te ly Operated Valves (ROV) is to provide quick shutoff in cases where loss of containment e.g. at the pump as a result of seal failure, could result in a major hazard. Typically ROV should be installed in suction of pump if suction vessel: • contain more than 5 tons of C4 or lighter hydrocarbon • contain more than 5 tons of liquid above auto ignition • contain toxic liquids (refer API 750 Appendix C)

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Remotely Operated Valves (ROVs) shall be placed in a fire resistant box with fireproofed cables (for MOVs) for flammable fluids. The valves shall at least be TSO (tight shut off) Class IV. In case the ROV is a motor operated valve, the valve shall be provided with emergency power supply as per requirement of OISD-149.

Fire and Gas Detection System The purpose of the fire and gas detection system shall be to detect a fire or gas release and initiate alarm and subsequent action.

Detection devices can be classified based on their application as follows: • Fire detectors : Smoke, Heat, Flame • Gas detectors : Flammable, Toxic • Dust detectors : Combustible Following points need to be considered while designing a Gas detection System: • Leak Size • Consequence analysis • Type of detector and working principle • Location of detectors based on voting logic, leak source, coverage area

• • • •

Recommend facilities required to mitigate fire risk Confirm the proposed plant layout Determine the design flows for the required fire protection system Develop fire and gas detection philosophy

Fire protection is typically achieved by means of: • Active fire protection such as hydrant & water sprinkler system, foam system, clean agent system etc.

• Passive fire protection such as fire proofing, fire detection and alarm system etc.

OISD-116 provides guidelines for design of fire protection facilities for petroleum refineries and oil/gas processing plants. OISD-164 provides recommendations for fireproofing in oil & gas industry.

Conclusion To summarise, the HSE engineer must get involved in all phases of project execution from concept to commissioning and ensure that all aspects of HSE are incorporated in design resulting in a safe, reliable, operable and maintainable plant. It is the responsibility of HSE engineer to propagate a proactive HSE culture across the multi-disciplinary project team. sw

In general, gas detectors are located at following potential points of release depending on the hazardous and toxic nature of process fluid: • Light Hydrocarbon Pumps • Gas compressor seals and inside analyser houses • Process cooling tower top platform in the units having pressurised cooling water return • Fuel gas knock-out drum • Suction side of forced draft air blowers if located where hydrocarbon vapours may be present • LPG Horton spheres, pump house • Hydrocarbon bulk truck loading area • Class A product storage tanks in tank farm For buildings which are located in the possible path of a gas cloud, gas detectors shall be provided at the inlet of the HVAC (heating, ventilation, and air conditioning) system to initiate HVAC shut down or switch the system to recirculation mode.

Fire Protection System The fire protection system is designed based on fire safety study with following objectives: • Identify the possible fire scenarios within the plant highlighting any equipment of elevated fire risk • Determine which fire scenarios require simultaneous operation of different fire protection systems

>> HSE engineer must get involved in all phases of project execution from concept to commissioning and ensure that all aspects of HSE are incorporated in design resulting in a safe, reliable, operable and maintainable plant. www.oswindia.com

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Shubha Deo Deputy General Manager Uhde India Private Limited

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features Air Vaporiser for LNG Regasification

Reducing Carbon Footprint LNG imports and regasification is essential to meet energy demand of India. During regasification of LNG, ambient air and sea water are economical resources to meet heat requirements. This coupled with LNG cold energy integration by generating power will offer tremendous savings in fuel gas consumption and there by reduction in carbon footprint.

LNG import is one of the major options to India’s energy security. To meet our energy demand, the imported LNG needs to be regasified in LNG terminal to feed in to gas grid. Typically these regasification terminals consumes about 1% to 1.5% plant throughput as fuel to generate electricity to meet the power requirements. The main operating cost of LNG regasification terminal is the LNG Vaporization. Substantial heat duty (Approx. 800 KJ/Kg of LNG) is required for LNG vaporization and it is always a challenge to provide this energy in most optimum way to reduce carbon footprint. Simultaneous use of cold energy of LNG will substantially reduce the fuel requirement of terminal. It is challenge to designers & operators to conceive various ways to utilise this cold energy in terminal and or in adjacent industrial complexes.

LNG Vaporisation LNG Vaporisation technology selection is based on available conditions of vaporisation medium like ambient air, sea water, natural gas etc. The suitability of type of vaporisation need to be studied for each case comprising the various vaporisation options like: • Submersible Combustion Vaporiser (SCV), where natural gas is used as a heat source.

• Open Rack Vaporiser (ORV), where sea water is used as heat source.

• Shell & Tube Vaporiser (STV), where sea water is either directly or indirectly used as heat source.

• Ambient Air Vaporiser (AAV), where ambient air is used directly as heat source.

• Indirect Ambient Air Vaporiser (IAV) where ambient air is indirectly used as heat source through intermediate heating medium.

In this paper, discussions are limited to Ambient Air Vaporisers; those are generally suitable for tropical and sub-tropical climatic conditions.

Ambient Air LNG Vaporisers (AAV) Ambient Air Vaporisers using Natural Convection of Air or Using Forced Draft Fan: In this type of vaporiser, thermal energy of air is transferred to LNG through a series of surface heat exchangers, where the air travels down the heat exchanger.

In natural convection type AAV, air flow is controlled by natural buoyancy of the cooled dense air, whereas in forced draft type AAV, air flow is regulated through forced draft fan mounted on top of vaporiser. Liquid LNG flows inside through the tubes and picks up heat for vaporisation from the air flowing on the outside

of exchanger surface. Vaporiser is equipped with aluminium fins to increase the heat transfer area. Air Flow in forced draft vaporiser is approximately 1.7 times more than natural draft vaporiser, hence heat transfer area will be lower, and so fewer units are required. However, ice formation rate is more in forced draft type due to high velocity of air leading to more condensation of water from air on vaporiser surface.

Ambient Air Vaporisers is the best suited for tropical climate and is a proven technology. However, there are certain issues associated with this type of vaporiser, notably fog formation, icing of vaporiser surface towards the lower part and cold air recirculation. To overcome non availability of unit due to icing, spare vaporiser unit is normally provided and after fixed running hours (typical cycle of 4-8 hours) vaporiser in operation is taken out of service for defrosting.

Operating expense of forced draft type is slightly more than natural draft type due to power consumption in Air Fans.

Indirect Ambient Air Vaporiser (IAV) In this type of vaporiser, LNG is vaporised utilising ambient air with an intermediate heating fluid. Intermediate heating fluid used is generally glycol water. In IAV, glycol water is heated by ambient air using forced draft fans. This heated glycol water then transfers thermal energy to LNG in a shell & tube vaporiser (STV). Glycol water continuous circulation between IAV and STV is maintained by a dedicated glycol water pump. Transfer of thermal energy from ambient air to glycol water is a function of ambient design temperature and it is affected by other considerations such as cold air re-circulation. Generally large footprint is required for this type of vaporiser. IAV is well proven technology and also it is environment friendly technology as it offers low carbon footprint.

For plant location where ambient temperatures are very low for most part of the year, the applicability of IAV may not be attractive due to incremental cost associated with increased CAPEX (number of fans, air heater bays and supplemental SCV) and OPEX (incremental power consumption in air heater fans, glycol water pumps and fuel for supplemental SCV).

Reverse Cooling Tower based LNG Vaporiser Another indirect air type of vaporiser is “Reverse cooling tower or Heating tower”.

In this type of vaporiser, ambient air heat is transferred to direct heating of cold

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water, then heated water is used to heat the glycol water, which in turn vaporises LNG in shell and tube vaporiser.

Heat transfer coefficient in heating tower depends upon water side resistance also unlike normal cooling tower where heat transfer coefficient largely depends upon air side resistance. This is due to condensation of water in heating tower. Heating tower is sized for design ambient temperature and humidity based on weather data analysis.

Heating tower type of vaporiser is also environment friendly as it consumes less energy and also it is proven technology.

Design Consideration of Ambient Air Vaporiser Ambient air thermal energy is utilised for LNG vaporisation in heat exchanger either through natural convection of air or forced draft or through intermediate fluid with forced draft. Heat transfer in all ambient air type of

Procedure for study of ambient air based Vaporisation system can be described as given below: • Estimate required LNG Vaporisation Duty.

• Collect data: historical ambient air condition (temperature & humidity) of site (daily maximum & minimum).

• Use CFD to determine actual ambient temperature in contact with air heat exchanger for given equipment layout and optimise layout to get the best performance of air heat exchanger.

• Based on actual ambient temperature, determine suitability of air heat exchanger for worst (winter) condition. Then determine the requirement of supplementary vaporiser to meet total vaporisation duty.

Differential heat duty (for winter months) can be achieved by installing submerged combustion vaporiser (SCV). However, requirement of SCV needs to be studied on case by case basis like for plants located in tropical climate, additional heater may not be required or if winter duration is very short, then plant load can be reduced (if feasible).

Indirect Ambient Air Vaporiser with Rankine Cycle to Generate Power: As discussed in previous sections using ambient air as a heating medium reduces the requirement of fuel consumption in LNG regasification terminals. In order to

Figure 1: Time occurrence for a typical tropical site

vaporisers depends upon the ambient air temperature in contact with heat exchanger and humidity. Air exchangers are normally designed for ambient temperature such that site ambient temperatures are greater than design ambient temperature for more than 90 per cent of the time in a year. An ambient temperature – time occurrence cur ve for a typical tropical site is given below.

From above Figure 1, we can infer for this typical tropical site that the design point of air exchanger can be around 20 deg C as 90 per cent of time in a year the ambient temperature is above that temperature. And for a period (~ 10 per cent) when ambient temperature is less than 20 deg C, either supplementary vaporiser like SCV can be provided or alternatively plant throughput can be reduced. Based on such curve, design point of air exchanger can be determined for any site climatic conditions. It is to be noted that lower the design temperature, larger the air heat exchanger size for given temperature approach, duty and flow-rate of fluid.

A m b i e n t a i r t e m p e r a t u re i n c o n t a c t w i t h h e a t e x c h a n g e r c a n b e different than actual ambient temperature due to cold air recirculation.

For actual design of air exchanger cold air recirculation phenomenon n e e d s to b e s t u d i e d i n d e t a i l u s i n g co m p u t at i o n a l Fl u i d D y n a m i c s (CFD) tool. www.oswindia.com

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Figure 2: The concept of Rankine cycle with propane as intermediate fluid

further reduce the energy consumption to improve carbon credit of regasification terminals, the innovative utilisation of cold energy need to be looked into.

One of the schemes to utilise LNG cold energy is to generate electrical power using the concept of Rankine cycle with propane as intermediate fluid, which is described in Figure 2.

LNG is vaporised in propane condenser where cold energy of LNG is transferred to vapour propane to condense it. Vaporised LNG is superheated to required send out conditions in glycol water (GW) - LNG heater. Liquid propane from propane condenser is transferred to propane vaporiser through pump. Heat of vaporisation of propane is provided through air heaters using glycol water loop. In air heater, glycol water is heated by ambient air through forced draft fan mounted on top of air heater. Glycol water then passes this thermal energy

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Indirect Ambient Air IndirectAmbientAirVaporiser Vaporiser (IAV) with cold (IAV) with standalone energy power production captive power plant Power Requirement of Little higher than base LNG Regas. Facility

Base

Power from ‘Expander

Can be produced to meet NIL (*) required power

Fuel Gas Consumption

No fuel is required

Very High

Fuel Gas cost

NIL

Very High

* Captive power plant is required Table 1: Comparison of indirect air ambient vaporiser with and without cold energy integration.

to propane for vaporisation. Vaporised propane is then expanded in Expander which utilises the useful energy to produce power through generator.

IAV with cold energy integration can generate enough power to meet all its normal power requirements, in turn offering significant savings in energy consumption.

A comparison of indirect air ambient vaporizer with and without cold energy integration is given in Table1.

Conclusion To meet India’s energy appetite, LNG import / regasification is one of the immediate options. Ambient air and sea water are most economical sources to meet the heat requirement of Regasification. This coupled with LNG cold energy integration by generating power will offer tremendous savings in fuel gas consumption and there by reduction in carbon footprint. sw Reference •

Utilization of Atmospheric Heat Exchangers in LNG Vaporization Processes: “A comparison of systems and methods” Presented at “2008 American Institute of Chemical Engineers (AIChE) Spring Meeting” By Rajeev Nanda & Tom Dendy.

Power generation in Expander is a function of propane vapour inlet pressure, which depends on glycol water temperature, which in turn depends upon ambient air temperature. As the ambient temperature increases, power generation through expander also increases.

Intermediate fluid is selected such that its condensation temperature at low pressure is suitable to vaporise LNG and also it shall be vaporised at near ambient temperature conditions at reasonably high pressures for expander operation.

Propane nearly fits to this criterion. This scheme with propane Expander generates sufficient power for normal operation of standalone Re-gasification facility. Expanders are normally highly reliable equipment and its service is also very clean, hence no shutdown is envisaged other than regular maintenance which can be supported by state grid.

Air heater, which is provider of heat to system to be sized for optimum ambient temperature and humidity considering detail analysis of weather of site as discussed in earlier section.

Advantages of this cold energy integrated vaporisation scheme are: • Meets plant power requirement through cold energy recovery hence very low operating expenses • Best suited for tropical climate however can be tailored for other climatic condition also • LNG Vaporisation is possible even if Expander is out of service by operating Bypass JT Valve • Cold energy recovery for power generation is a proven technology and coupled with Ambient air heater, it is economical and environment friendly • Negligible greenhouse gas emission i.e. low carbon foot print. Even though CAPEX of this scheme is high, the payback time is very attractive.

Case Study of Indirect Ambient Air Vaporiser Using LNG Cold Energy to Generate Power A comparative study of “Indirect Ambient Air vaporizer (IAV) with cold energy integration to generate power” with “IAV without cold energy integration” for a typical 5 MMTPA LNG Regasification plant is carried out. This study showed that

Anand Kumar Principal Engineer – Process Technip KT India Limited anakumar@technip.com Dattesh V Kondekar Principal Engineer – Process Technip KT India Limited dvkondekar@technip.com M K E Prasad Sr Vice President – Process and Technology Technip KT India Limited mkeprasad@technip.com

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features Energy Watch

Energy Commodities Prices Rise Albeit at Varying Levels Energy commodities prices were on rise in the past two months of July and August 2013, albeit at varying levels. While CER futures prices on ICE-ECX platform rose the most by 18 per cent (albeit with low price base) as the EU parliament approved an amended backloading plan, NYMEX natural gas futures registered the minimal price rise of 0.45 per cent during the period on fluctuating US summer weather forecasting.

NYMEX (CME) light sweet crude oil (WTI) futures started the month of July at USD 97.99 per barrel, up by 1.48 per cent from the previous months close owing to data release showing gains in European manufacturing activity.

Fur ther, positive economic data from the US, Japan and the Euro zone continued to bolster crude oil demand sentiments, helping the oil prices to continue its upward trend, which continued almost through the two-month period. Consequently, the opening day’s low of USD 96.07 eventually emerged as the two-month low. Later, apart from positive economic data releases, concerns over persisting political turmoil in Egypt and Syria continued to help the oil price rise. Crude oil prices were also boosted by a US government report confirming a decline in weekly crude oil supplies. Later, while, market participants deliberated the outlook for energy demand against a backdrop of 7.5 per cent second quarter economic growth in China, a rise in July New York manufacturing conditions and positive US jobless claims numbers helped the sustenance of uptrend in crude oil prices. Consequently, crude oil futures moved up to interim high of USD 109.32 on July 19.

Later, a weak appraisal for manufacturing activity in China and disappointing earnings from Caterpillar Inc., a bellwether for the world economy, leading to a subdued outlook for energy demand, pulled down oil prices. Further, increasing worries on slowdown in Chinese growth and feeble concerns over hurricane activity in the Atlantic kept some pressure on oil prices. Barring for some brief sessions, oil prices continued to drift downward largely on recovery in Libyan crude oil production. By mid of August, oil prices tend to stabilise as rise in Chinese industrial production and shutdown of two of Libya’s biggest crude oil export terminals supported crude oil prices. Though unabated violence in Egypt raised worries over oil supplies in the Middle East; oil prices rose in measured steps amidst release of disappointing US manufacturing data and worries over removal of economic stimulus by the Fed. In the later part of August, crude oil prices resumed its upward trend as better than expected manufacturing data from China, the world’s second largest oil

Source: Bloomberg

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consumer, enhanced energy demand. The euro-zone continued to recover with increase in its business activity, further supporting crude oil prices. News reports that US was contemplating military intervention following reports of chemical attacks in Syria, injected fresh concerns over crude oil supplies and thus placed upward pressure on prices. Amidst supply concerns owing to tension in Syria, crude oil futures moved to a month high of USD 112.24 on August 28. Later, as worries that the US might stage a military strike on Syria eased, oil prices moved down to close the month of August at USD 107.65, marking a rise of 11.49 per cent in two-months period.

In emission market segment, prices of both European Union allowances (EUA) futures and CER (Carbon Emitted Reduction) futures jumped by 8.33 per cent and 18 per cent respectively in the two month period, on ICE-ECX platform. The spike in prices came especially in CERS (given low base) as EU lawmakers backed a EU Commission’s plan to choke supply of permits in the market. Further, carbon prices extended their upward trend on several well-bid auctions for carbon units. sw (The views expressed by the authors are their personal opinions)

The uptrend in crude oil prices was also reflected in crude oil’s two popular derivates i.e. heating oil and gasoline. Besides crude oil prices impacting factors, refinery problems in US also fed major supply concerns, thereby pushing gasoline futures prices and heating oil futures prices (on NYMEX platform) up by 9.69 per cent and 9.02 per cent respectively. On the contrary, the other major energy commodity natural gas futures (traded on NYMEXCME platform) saw a price rise of just 0.45 per cent in two month period.

Fluctuating summer weather forecasting in US, in turn impacting heating demand sentiments in natural gas, led to a range-bound natural gas price movement. Further, increase in US gas inventory levels denied any major rise in gas prices.

The other energy commodity that showed relatively flat price movement was coal. ICE Rotterdam monthly coal futures prices moved up by just 1.41 per cent during the two months period of July-August. While a strike at US coal miner Drummond’s operations in Colombia removed some coal supply from the market, plentiful supply from other producers in the Americas and Russia avoided sustained tightness in physical market. Additionally, slashing of domestic prices by major Chinese producers in a move likely to slow import growth was again countered by the news that unions in the world’s fifth largest exporter South Africa declared a dispute over wages, thereby resulting in range-bound price movement for coal. www.oswindia.com

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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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news

India Oil Ministry to Divert Non-Priority Gas to Power Units Cabinet Clears IOC Disinvestment New Delhi, India: To give a boost to power units, the Oil Ministry has proposed to divert some natural gas from non-priority consumers to the fuel-starved units that will be enough to generate 240-480 mw electricity immediately and about 2,400 mw after two years, according to oil ministry. The oil ministry has managed approx. 1-2 million standard cubic meters per day (mmscmd) gas for power units that could be supplied in the current FY. It can be raised to 2-3 mmscmd by 2014-15 and about 10 mmscmd by 2015-16. The additional gas is managed from blocks held in joint ventures between state energy firms and private companies such as the Rajasthan block and Panna, Mukta & Tapti (PMT) oil and gas fields.

New Delhi, India: In accordance to the Government of India’s disinvestment policy, the Cabinet Committee of Economics Affairs (CCEA) has approved the disinvestment of 10 per cent paid-up equity in the Indian Oil Corporation Limited (IOCL), out of its equity capital holding of 78.92 per cent.

After this disinvestment the Government of India shareholding in the company would come down to 68.92 per cent. The disinvestment will be through Offer for Sale (OFS) method in the domestic market according to the SEBI rules and regulations.

CAG Accuses State-run Oil COs for Undue Favour Petroleum Ministry to Rework Shale Policy New Delhi, India: The Petroleum Ministry now will have to rework on its to Private Sector New Delhi, India: Comptroller & Auditor General of India (CAG) has accused that private refiners has gained ` 101.96 billion in five years due to passing undue favour of state-run oil companies pricing system. In a report, CAG has also censured the oil ministry for causing a revenue loss of over ` 1560 billion over the same period. The controversial formula, which also applies to retail buyers at petrol pumps, makes diesel costlier because buyers are forced to pay additional costs that companies do not incur, such as customs duty. As a result, state firms also gain handsomely from sales to retail customers.

This is an additional benefit for state refiners when they sell to customers, and for private refiners such as Reliance Industries and Essar Oil when they sell to state firms.

Current Gas Price Hike to Woo FDI: Moily New Delhi, India: Petroleum Minister M Veerappa Moily has justified the recent gas price hike from USD 4.2 to USD 8.4 by saying that the government needs to take bold decisions if it wants the Global oil major like Chevron’s and the Exxon’s of the world to come and invest in India’s energy sector. The minister said that China is far M Veerappa Moily, Union Petroleum ahead of India due to its investor-friendly polices Minister that entice most big global energy companies.

“In India, have you seen any big global energy companies... only one BP Plc has come, which, too, we are trying to drive away by opposing important decision like the recent gas price hike.” It was time that India took investor-friendly decisions to achieve long-term economic gains.

India currently spends USD 160 billion in a year on its oil imports. Moily insisted for producing more domestic oil & gas from the North East regions which are sailing on gas. He articulated in exploring not just the Krishna Godavari basin but other basins including Cauvery and Mahanadi that have good reserves of oil and gas. So our efforts should be to encourage investors to explore oil and gas from these potential sites, he added. www.oswindia.com

news india rakesh 2.indd 40

shale exploration policy after the Finance Ministry objected the Ministry’s proposed move to allow existing oil and gas explorers to find shale gas in their respective blocks on the grounds that it was against the existing production sharing contracts. The Petroleum Ministry, which is working on a shale gas exploration policy, felt that this modus operandi would help faster exploitation of shale gas and the Petroleum and Natural Gas Minister M Veerappa Moily is of the view that as in the US, shale gas can emerge as an important new source of energy for India, too.

In this regard, the other option is to hold auction rounds, which may take a couple of years more, as suitable policy is yet to be put in place. Public sector explorer ONGC has already undertaken an experimental project to explore shale gas. However, it cannot go ahead commercially because the country does not have a shale gas exploration policy.

Cairn’s Prospective Revamps with Increase Crude Production of Rajasthan Jaipur, India: While domestic oil exploration company is gaining from rupee depreciation, Cairn India stock has been moving in the second FY driven by higher production and reserve upgrades of its Rajasthan oil output. The company’s Rajasthan block produced around 1,73,000 bopd during the quarter. It is predicted that the Rajasthan oil output to increase further during rest of FY14, as more infill wells are brought on production.

Cairn India plans investment of ` 16 billion (USD 3 billion) over next three year i.e FY14-16 in pursuit of finding and producing more oil. Out of this majority i.e. ` 130 billion is directed towards Rajasthan Block itself where company will drill more than 450 wells – approximately 100 exploration wells and more than 350 development wells. The company had exited FY13 with an oil production of 2,05,000 barrels of Oil per day (bopd) after Aishwarya Fields in the Rajasthan block started oil production. The other two Mangala and Bhagyam fields in the Rajasthan Block have already been producing oil. The company now is betting big on the Barmer block in Rajasthan, which can provide a big boost to company’s oil reserves and production.

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Petronet Proposes IOC to Drop Ennore LNG Terminal Ennore, India: Petronet has proposed one of its promoters Indian Oil Corp (IOC) to drop plans for a greenfield LNG terminal at Ennore and has offered to meet all of its gas needs.

In a letter to IndianOil Chairman R S Butola, A K Balyan, CEO Petronet, has argued it would make more economic sense for IOC to lease capacity in Petronet’s terminals and import its own gas through it. He urged that Petronet was ready to offer as much capacity as IndianOil wanted in its eastern terminals.

Govt to Build Four New Crude Oil Storage Facilities New Delhi, India: The government of India has proposed to set up an additional 12.5 million tonne strategic crude oil storage capacity in the country, told Panabaaka Lakshmi, Minister of State for Petroleum & Natural Gas, to the parliament.

The project, which is being implemented

by Indian Strategic Petroleum Reserves Ltd (ISPRL), will be set up at four locations – Bikaner, Rajkot, Chandikhol and Padur – in the country. ISPRL has conducted a detailed feasibility study for construction of these storages in phase-II. In the first phase, ISPRL is setting up storage facilities of 5.33 million tonnes of crude oil at Visakhapatnam (1.33 MT), Mangalore (1.5 MT) and Padur (storage capacity: 2.5 MT) to enhance India’s energy security.

Panabaaka Lakshmi, Minister of State for Petroleum & Natural Gas

RIL Eyes US Petrochemicals Sector Mumbai, India: On the back of the US shale gas business, Reliance Industries Ltd (RIL), the Mukesh Ambani led oil and gas major, is now exploring opportunities in refinery/ petrochemicals, fertilisers, power generation and coal mining in that country.

While Petronet is all set to starta 5 million ton-a-year import facility at Kochi in Kerala and a similar-capacity terminal on the Andhra Pradesh coast in 2016, IOC plans to build LNG plants at Ennore in Tamil Nadu and Dhamara port in Odisha, primarily to meet the gas needs of its refineries.

Balyan said that Petronet’s Kochi facility and the upcoming terminal at Gangavaram in Andhra Pradesh provide easy connectivity to meet all of IOC’s gas needs at the Chennai refinery.

HPCL Reconsiders to Import Crude from Iran Mumbai, India: State-owned Hindustan Petroleum Corp Ltd (HPCL) plans to import 1 million ton of crude oil from Iran this fiscal if issues in getting insurance cover for processing oil from Tehran are resolved.

HPCL has not bought any oil from Iran after insurance companies said they will not provide cover for refineries processing Iranian oil.

B K Namdeo, Director (Refineries), HPCL, said that in 2012, HPCL had a contract to import 2 million ton on firm basis and another 1 million ton of optional imports from Iran. We imported 2.1 million ton. This year, we have an optional contract to import 1 million ton, he aded.

L&T to Spin off Hydrocarbon Unit Mumbai, India: The hydrocarbon division of L&T has to be necessarily carved out into a subsidiary to achieve its potential and tap global opportunities, said A M Naik, Chairman, L&T, when addressing an extraordinary general meeting convened on directions of the Bombay High Court to obtain shareholders nod on the issue.

The L&T board has approved a scheme of arrangement for consolidating the assets and liabilities of its hydrocarbon business with its wholly owned subsidiary L&T Hydrocarbon Engineering Ltd (LTHE).

Saudi Armco Eyes OPaL Stake

Reliance has already worked out investments of USD 1.5 billion annually for the next three years in the shale business there. It has invested USD 6 billion in shale operations till the first quarter of this fiscal and produced a cumulative 183.1 billion cubic feet of gas equivalent — comprising natural gas liquid, condensate and shale gas.

Ahmedabad, India: Saudi Aramco, the world’s biggest oil producer, is paving the way to entry into the Indian oil and gas sector by planning to acquire up to 30 per cent stake with a key management role in a giant petrochemicals project in Gujarat, and is negotiating with ONGC Petro additions Ltd (OPaL).

The company posted an 84 per cent rise in revenue from its shale gas venture in the US on rising production during the first quarter. RIL has three joint ventures, with Chevron, Pioneer Natural Resource and Carrizo Oil & Gas, and a midstream joint venture with Pioneer for its shale business in the US.

The proposed deal, currently at an advanced stage, will be mutually fruitful as Middle-East oil suppliers are looking for closer links in large Asian markets, with the American continents likely to depend less on crude oil imports as domestic shale production and deep-sea oil and gas output pick up.

Mukesh Ambani, Managing Director, RIL

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news GAIL to Sell its Stake in China Gas Holdings

New Gas Discovery at KG Basin Mumbai, India: A new gas condensate discovery off the east coast of India in the Cauvery basin, announced by the operator Reliance Industries Ltd (RIL) and its partner BP. The discovery, in the deepwater block CY-DWN-2001/2 (CYD5), is situated 62 km from the coast in the Cauvery Basin and is the second gas discovery in the block. Reliance is the operator of the block with a 70 per cent stake and BP has a 30 per cent share.

The company said that well CYIII-D5-S1 was drilled in a water depth of 1,743 meters, to a total depth of 5,731 m, with the primary objective of exploring Mesozoic-aged reservoirs. Preliminary evaluation of well data and fluid samples indicated presence of gas condensate in the reservoir interval with a gross column of 143 m, it said.

BHEL Bags BPCL’s Supply Contract Kochi, India: State-run BHEL has bagged a ` 2.65-billion order for supplying the Gas Turbine Generator package for an energy efficient and environment friendly co-generation captive power plant at Kochi Refinery from Bharat Petroleum Corporation (BPCL). The order envisages supply and supervision of three gas turbines of 34.5 MW rating each, with associated auxiliaries and control systems.

The gas turbine will be operated in the cogeneration mode for meeting the power and process steam requirement of the upcoming Kochi refinery expansion project.

The equipment for the project will be supplied by BHEL’s Hyderabad plant and Electronics Division, Bangalore. Erection and commissioning of the Gas Turbine package will be carried out by the company’s Power Sector - Southern Region.

BHEL offers units from 10 MW onwards for both steam turbine-based and gasbased combined cycle power projects for complete power, and process steam requirements of various industries.

CIL to Develop CBM Reserves

Pratik Prakashbapu Patil, Minister of State for Coal

New Delhi, India: Coal India Ltd (CIL) in association with Central Mine Planning & Design Institute (CMPDI) is pursuing development of Coal Mine Methane (CMM) from its mining areas as it would be beneficial on mine safety as well as environment, Pratik Prakashbapu Patil, Minister of State for Coal, has informed in Lok Sabha.

Ministry of Coal has made CMPDI the Nodal Agency for development of CMM in India.

CIL/CMPDI has successfully implemented a CMM demonstration project at Moonidih mine of Bharat Coking Coal Ltd (BCCL), funded by GoI/UNDP/ GEF. The successful implementation of the project has proved the efficacy of the technology of CMM extraction and its utilisation in Indian geo-mining condition. Based on success of the demonstration project, steps have been taken for identification of prospective areas for development of CMM projects and coalfields characterized by occurrence of multi-seams of high rank coals which were considered potential areas for CMM development. www.oswindia.com

news india rakesh 2.indd 42

New Delhi, India: State-owned gas utility GAIL India Ltd will sell part of its 4.6 per cent stake in Hong Kong-listed city gas distribution firm China Gas Holdings. GAIL had acquired 210 million shares of the China Gas in 2005 with an investment of ` 1.37 billion. The gas utility plans to keep a small strategic interest in the company that will help it retain its board position in China Gas. The board of GAIL has accorded approval to partially divest its equity stake in China Gas for recoupment of entire initial investment, while retaining the strategic advantage as envisaged at the time of initial investment.

India, Venezuela in More Hydrocarbon Collaboration New Delhi, India: Venezuela and India have agreed to develop more collaboration in hydrocarbons sector. In his recent visit to India, His Excellency, Rafael Ramirez, Minister of Energy and Mines of the Bolivarian Republic of Venezuela met his counterpart, Dr. M Veerappa Moily, Minister for Petroleum and Natural Gas, Government of India and reviewed on-going cooperation in the hydrocarbons sector.

Minister Ramirez appreciated participation by Indian companies in the upstream exploration and production sector and also the companies that were major off takers of Venezuelan crude oil. He expressed that Indian oil and gas companies were very well accepted in Venezuela and encouraged the Indian oil and gas companies to scale up their participation in the prolific Venezuelan oil and gas sector.

Detained Oil Tanker by Iran Arrived Visakhapatnam, India: Shipping Corporation of India’s (SCI) oil tanker, MT Desh Shanti, which was detained in Iran, has arrived at Visakhapatnam port.

The vessel was detained on August 12 by the Iranian Revolutionary Guards Corps (IRGC) in the Persian Gulf while carrying oil from Basrah in Iraq to Visakhapatnam. The Iranian authorities had detained the ship carrying 140,000 tonnes of Iraqi crude, citing environmental and pollution concerns, despite Indian protests. India had strongly objected to the detention, saying it was in transgression of UN Convention on the Laws of the Sea and warned of serious ramifications. It was released after the SCI, India’s largest shipping company, submitted a letter of undertaking to the Iranian Ports and Maritime Organisation.

Domestic Gas Production to Reach 183 mmscmd

by FY20: ICRA Mumbai, India: In the outlook of future discoveries, India’s domestic natural gas production, which has steadily declined in the last two years, is expected to increase around 183 mmscmd by FY20 from 111 mmscmd in FY13, according to a report by rating agency IRCA. The report said that the domestic natural gas production is expected to increase from 111 mmscmd FY13 to around 125 mmscmd by FY16, from existing or already discovered fields. This could further increase to around 183 mmscmd by FY20.

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Iran Scraps Oil & Gas Links to India New Delhi, India: The new Iranian government has withdrawn all crucial oil & gas concessions that had been promised to India by its predecessor.

Bijan N Zangeneh, Iranian Oil Minister, informed Indian ambassador D P Srivastava that Iran would not accept the entire payment for crude oil imported by India in rupees as its predecessor had agreed to the entire payment for crude oil imported by India in rupees in July 2012. India was banking on 100 per cent rupee payment for Iranian crude to cut its forex outflow.

A major blow for India as Petroleum Minister M Veerappa Moily had assured Prime Minister Manmohan Singh to increase crude oil imports from Iran that can save USD 8.47 billion for an additional 11 million tonnes crude oil in the remainder of the fiscal. Iran has since stopped issuing invoices in rupees for

the full quantity of crude and reverted to the old system of accepting only 45 per cent of the payment in rupees. Zangeneh told Srivastava that the new Central Bank of Iran governor had complained of difficulties in transferring money in euros from India to other countries to pay for food and medicines.

Zangeneh wants India to renegotiate the terms and revert to majority euro payment.

Iran also cancelled the previous regime’s offer to sign a production sharing contract (PSC) for the Farzad B offshore gas field, which three Indian state-sector companies had jointly won the block in 2002 from the National Iranian Oil Company. ONGC Videsh and Indian Oil Corporation had 40 per cent of stake each; Oil India Lid had the remaining 20 per cent.

Private Entity Barred from Shale Exploration

Rupee Impact Highest for Indian Downstream OMCs: Fitch

New Delhi, India: The cabinet has approved the shale gas and oil exploration policy that will allow only the state-owned oil companies to carry out exploration and production of the unconventional hydrocarbon from onland blocks, bars private entity from it. The long-awaited policy will pave the way for state-run ONGC and Oil India to explore and produce shale oil and gas from blocks allotted on a nomination basis before advent of the New Exploration Licensing Policy in 1999, but prevents participation of successful private explorers such as Reliance Industries, GSPC and Cairn India and restrict exploration of shale resources in only five onland basins.

Earlier, the oil ministry had said all existing operators could be permitted to explore shale resources, along with conventional oil and gas. But later the government decided to have a separate policy later to deal with exploration of shale resources in blocks awarded to private firms for conventional oil and gas and coal bed methane.

New Delhi, India: The continuous rupee depreciation has varying levels of implications for rated energy and utilities sectors in India, but not affected their rating immediately, said global rating agent Fitch Ratings Inc. Among the Indian energy sector issuers currently rated by Fitch, the risks to standalone financial profiles are highest for state-controlled petroleum marketing companies among the Indian energy sector. The Indian rupee has depreciated by over 25 per cent versus the dollar since 1 April 2013. Fitch expects limited negative credit implications for most of the rated issuers due to natural or financial hedges or, in the case of utilities, tariff mechanisms that allow for exchange rate fluctuations.

The policy also bars exploration of shale oil and gas in 254 blocks, awarded to several public and private sector energy firms in nine rounds under the new exploration licensing policy (NELP) regime in last 15 years. Even pre-Nelp blocks such as Cairn-operated Rajasthan oilfields and coal bed methane (CBM) blocks are kept out of its preview.

PM Instructs Oil Ministry to Reduce Oil Bill New Delhi, India: Prime Minster Dr Manmohan Singh has instructed Oil Ministry to save USD 25 billion on oil imports in this financial year to help reduce the current account deficit (CAD), said Veerappa Moily, Union Oil Minister. The Oil Minister said that his ministry have already made efforts to save USD 22 billion and will make attempts for another USD 3 billion.

The move comes at a time when the sharp depreciation of the rupee is threatening to upset the Centre’s fiscal math by causing a spike in the oil import bill.

The forex savings on oil imports planned through a set of measures including an increase in imports from Iran where the payment is made in the rupee is pegged at 1 per cent of GDP. Other measures may include ethanol blending as well as improving project management and efficiencies. A one-time steep hike in the price of diesel was also said to be on the government agenda but Moily said this might not be an immediate option.

BPCL to Set up Polyurethane Plant in Kerala Kochi, India: Oil major Bharat Petroleum Corporation Ltd (BPCL) is all set to explore a 50:50 polyurethane joint venture in Kochi with city-based Manali Petrochemicals Ltd an outlay of around ` 25 billion. BPCL is expanding its refinery capacity at Kochi to around 15.5 million tonnes per annum (mtpa) from the current 9.5 mtpa. Once the expansion goes on stream, the company will have propylene capacity of 500,000 tpa - a quantum jump from its existing 50,000 tpa.

Govt to Share Insurance Burden on Iranian Crude New Delhi, India: While the General Insurance Corporation (GIC) awaits clarification from foreign re-insurers on their stand on cover for crude oil sourced from Iran, Indian refiners can go ahead as the proposed insurance pool set to take off. The Petroleum Ministry has informed that it will share the burden with insurance companies to set up the pool. Rajiv Takru, Financial Services Secretary, said that the Petroleum Ministry has agreed to provide an initial amount of ` 500 crore. This means any claim by a refinery importing crude from Iran will get honoured. Takru said oil refineries will continue their existing arrangements with insurance companies and the ` 2,000-crore Indian Energy insurance pool will act as a reinsurance support for the insurance companies in case of a claim.

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SUBSEA New Subsea Well Response Toolkit Concept Revealed UK: Oil Spill Response Ltd and the Subsea Well Response Project have detailed a collaboration to improve subsea well response capability using a subsea well containment concept and supplemental toolkit.This concept, engineered into a template containment system, is described in the Subsea Well Containment Guidelines.

It relies on standard readily available well test riser and surface equipment deployed offshore from a drilling rig to safely flow to surface, process and dispose of well hydrocarbons. The containment toolkit comprises equipment that is not currently available in the industry at short notice.

Containment capability is designed to complement a subsea well incident response in scenarios where capping alone is not sufficient to stem the flow of well fluids and to capture and dispose of them in a safe and controlled way.

The containment toolkit components will be stored and maintained ready for transportation at strategic international locations to facilitate timely response around the world, and will be available for industry use from the end of 2014.

First Gas flows from Dutch K-quad Subsea Tieback The Netherlands: Total E&P Nederland has produced first gas from the K4-Z field in the Dutch North Sea. The field is in license K4a, 140 km (87 mi) northwest of the port of Den Helder. The project, a 50/50 partnership with EBN, has potential to deliver around 11,500 boe/d.

K4-Z was discovered back in 1974, but remained undeveloped until the Dutch government introduced a marginal field policy and an accelerated depreciation measurement in 2010.

A two-well subsea completion has been installed, 17 km (10.6 mi) west of the K5 Central Complex, in a water depth of 36 m (118 ft).

The subsea facilities are linked to the K5-A platform.

Gas is exported through the WGT trunkline to the Den Helder gas terminal, with EBN will selling its share under an existing gas sales agreement. www.oswindia.com

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Deep, Ultra-deepwater Capex to Continue Growing to 2017 US: Infield Systems’ ninth Global Perspectives Deep and Ultra-deepwater Market Report to 2017 sees capex in those depths to grow over the next five years. The forecast is for water depths of 500 m (1,640 ft) and more.

Demand is pushing exploration further offshore into harsher and deeper waters, says Infield.

Deepwater reserve additions are expected to remain a marginal proportion of overall global production; rising from a 7 per cent cumulative share of global reserves in 2012 to 10 per cent by 2017. In capex terms, the deepwater market, which requires higher capital expenditure than its shallow water counterparts, is expected to rise from a 38 per cent share in 2012 to a 53 per cent share of global offshore capex by 2017.

Even with attention centered on the “Deepwater Triangle” of Brazil, West Africa, and the Gulf of Mexico, Infield sees support coming from less traditional deepwater arenas such as Southeast Asia, Australasia, and Europe. Substantial growth is also predicted for the Middle East and Caspian.

Subsea Stations Could Reduce Cost, Loads through Umbilicals UK: Subsea production requires injection of various chemicals and hydrate inhibitors conveyed from the topside production facilities to the subsea equipment via umbilicals. Chemical/methanol injection tubes enclosed within the umbilicals are designed to carry their products at a pre-determined flow rate and injection pressure. Main parameters governing the composition of the umbilical (the size and number of hydraulic tubes) are tieback length (managing the pressure drop caused by frictional losses in the tubes); flow rate, especially for methanol or low dosage hydrate inhibitor (LDHI); and the pump discharge availability at the topsides, typically 345 bar (5,000 psi).

Technip Bags Shell’s Subsea Contract Canada: Mexico: Shell Offshore Inc has awarded an engineering, procurement, and installation contract to Technip for subsea infrastructure at Stones in the Gulf of Mexico. Technip will install the subsea production system and Stones lateral gas pipeline, and also will provide associated project management, engineering and stalk fabrication. The production system design calls for dual 8-in insulated flowlines associated with pipeline end termination (PLET), and dual 8-in steel lazy wave riser (SLWR). The Stones lateral gas pipeline is comprised of a single 8-in gas pipel0ine associated with PLET, in-line sled, and a single 8-in SLWR. This field is in the Walker Ridge area in the US Gulf of Mexico, at a water depth of approximately 2,900 m (9,500 ft). This development will host the deepest water FPSO unit in the world and will be Shell’s first FPSO in the GoM.

Gas Production Restarts from Anoa Offshore Nigeria: Indonesia: Premier Oil has informed that the Anoa Phase 4 additional compression project offshore Indonesia has been completed and production resumed. The project will deliver an additional 200 bcf (5.7 bcm) of gas from the Anoa field via pipeline to Singapore. Among the company’s other projects off Indonesia are the Pelikan and Naga gas field developments. The fields hold 150 bcf (4.2 bcm) of reserves and will be tied into the Gajah Baru facilities. Fabrication of both wellhead platforms is nearing completion with load-out and installation scheduled by endSeptember. A rig contract has been awarded, with drilling due to start on the Pelikan platform wells following the monsoon season in 1Q 2014, followed by the Naga wells. First gas from both fields is slated for the second half of 2014.

Offshore World | 44 | AUGUST - SEPTEMBER 2013

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news DEEPWATER Sustained Growth Ahead for Deepwater Drilling US: Total investments in deepwater drilling could surge from USD 43 billion last year to USD 114 billion in 2022, according to a new study by Wood Mackenzie. Global drilling activity returned to pre-Macondo highs in 2012, the analysts claim, and the deepwater drilling sector is set for annual growth of 9 per cent over the next decade. Majors are driving much of the activity, and that trend should continue with a 39 per cent increase last year in deepwater and Arctic acreage licensed by the 20 leading deepwater players.

To meet the forecast exploration, appraisal, and development well numbers - set to rise from 500 to 1,250 wells per year - another 95 deepwater rigs will need to be built during 2016-22, WoodMac says. This will represent the longest period of deepwater rig construction to date. Tightness in the market has been driven by accelerated demand for new builds following Macondo, which has heightened the operators’ focus on risk mitigation.

Scond Deepwater Mozambique Well Comes up Dry Mozambique: Statoil’s second operated well offshore Mozambique was a dry hole, according to partner Tullow Oil. The drillship Discoverer Americas drilled the Buzio-1 exploration well in Area 2 in a water depth of 1,534 m (5,033 ft). Tullow has a 25 per cent interest in Areas 2 and 5 in the Romuva Basin, offshore Mozambique. Statoil 40 per cent are the operator while INPEX have a 25 per cent non-operated interest. ENH (Empresa Nacional de Hidrocarbonetos, E.P.) have a 10 per cent carried interest.

Signs of Oil Offshore Western Ireland Ireland: ExxonMobil plans to P&A its first deepwater exploration well offshore southwest Ireland. The 44/23-1 Dunquin North exploration well was drilled in around 1,700 m (5,577 ft) of water, 170 km (105 mi) from the southwest coast.

Drilling started in late April on the structure, situated on the northern flank of a 700-sq km (270-sq mi) intra-basinal ridge system in the southern Porcupine basin. Operations concluded on July 15 after reaching TD of 16,400 ft (4,999 m) MDBRT.

Solid Results from Latest Deepwater Well Offshore Tanzania Tanzania: The drillship Deepsea Metro I has completed BG/Ophir’s latest appraisal well offshore Tanzania.

Pweza-2 was drilled 2 km (1.2 mi) south of the Pweza-1 gas discovery well in block 4. The downdip location was chosen to improve understanding of the distribution and quality of the reservoir sands across the field. The well intersected 20 m (65.6 ft) of net pay, and confirmed pressure communication with Pweza-1. Ophir now assesses recoverable resources for Pweza at 1.7 tcf (49.02 bcm). The drillship has moved 5 km (3.1 mi) to the west to spud the Pweza-3 well, which is scheduled to include a drillstem test.

Anadarko Sells Deepwater Mozambique Interest to ONGC Mozambique: Anadarko Petroleum Corphas agreed to sell a 10 per cent interest in Mozambique Offshore Area 1 to OGNC Videsh Ltd (OVL) for USD 2.64 billion in cash. Anadarko will retain 26.5 per cent following the closing of the sale, expected before year-end. ONGC also has agreed to acquire additional interest in Area 1 from Videocon.

That deal is pending.

Area 1 is in the deepwater Rovuma basin and holds the Prosperidade and Golfinho/Atum natural gas fields with a combined estimated 35-65 tcf of recoverable gas reserves. Development of an LNG park with first cargoes in 2018 is under way. Partners in Area 1 also include Mitsui E&P Mozambique Area 1 (20 per cent), BPRL Ventures Mozambique (10 per cent), Videocon Mozambique Rovuma 1 (10 per cent), and PTT Exploration & Production (8.5 per cent).

Empresa Nacional de Hidrocarbonetos has a 15 per cent interest carried through the exploration phase.

Sri Lanka Offers Six Ultra Deepwater Blocks Sri Lanka: The Sri Lanka Petroleum Resources Development Committee has made available six ultradeepwater blocks of between approximately 18,000 and 26,000 sq km (6,950 and 10,039 sq mi) each around the country’s coastline on a Joint Study basis.

The blocks will be awarded outside the current bid round based on the experience and capability of the applicant along with their proposed work commitment, the news release said. The basic framework for the agreement is a two-year period of exclusivity for data acquisition, processing, and interpretation, followed by a year for discussions with the PRDC on potential next steps.

More Oil Found Offshore Newfoundland Canada: Statoil has made a third deepwater oil discovery in the Flemish Pass basin offshore Newfoundland.

The discovery is on the Bay du Nord prospect (EL1112) about 500 km (311 mi) northeast of St. John’s, Newfoundland and Labrador, Canada. In June, the company made a discovery at the Harpoon prospect, which is about 10 km (6 mi) from Bay du Nord. Both wells were drilled by the semisubmersible rig West Aquarius in about 1,100 m (3,609 ft) of water. Bay du Nord is about 20 km (12 mi) south of Statoil’s Mizzen discovery. The Mizzen discovery, announced in 2010, is estimated to hold between 100-200 MMbbl of oil.

Statoil is the operator of Bay du Nord and Harpoon with a 65 per cent interest. Husky Energy has a 35 per cent interest.

Oil Production Starts from Ultra-deepwater Sergipe Basin Brazil: Petróleo Brasileiro SA – Petrobras – has confirmed an extension to an ultra-deepwater discovery offshore in the Sergipe basin. The extension well, 3-SES-175D (3-BRSA-1180-D-SES), informally known as Muriú 1, is in the BM-SEAL-10 concession area, blocks SEAL-M-347 and SEAL-M-424. It reached TD of 5,627 m (18,457 ft) and confirms a 24-m (79-ft) thick reservoir. The well is 83 km (52 mi) from the city of Aracaju, 4.4 km (2.7 mi) from the discovery well, and at a water depth of 2,432 m (7,977 ft). Petrobras holds 100 per cent of the BM-SEAL-10 concession.

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products

NITRILE RUBBER FOR OIL & GAS

NEW OFFSHORE SAFETY RANGE

Krynac 4955 VP is a high-ACN nitrile rubber (NBR) for the oil and gas industries. The new material also features much improved flow properties for fast filling of large molds, without the need to add large quantities of plasticizers. Further it include optimized vulcanization properties and increased metal adhesion. The chemical component acrylonitrile (ACN) gives this elastomer its excellent oil resistance. Nitrile rubbers with an ACN content of over 39 per cent are regarded as particularly oil-resistant high-ACN grades.

LANXESS has a number of these grades, including Krynac 4975. Although LANXESS’ Krynac 4450 and 4045 are high-ACN NBR grades with significantly enhanced flow properties, their oil resistance cannot quite match that of the 4975 grade due to their lower ACN content. Krynac 4955 VP contains 49 per cent acrylonitrile. With a Mooney viscosity (ML (1+4) 100°C) of 55 ±5, however, it boasts far better flow properties than Krynac 4975 F. The new grade’s vulcanization performance has been optimized to such an extent that it combines far higher process reliability with excellent metal adhesion.

Survitec outlined a new addition to its range of offshore products and services: a range of Mass Evacuation Systems (MES) as a means of escape from distressed oil rigs and offshore platforms. The new MES range for both fixed and floating offshore installations and provides offshore customers with a one-stop-shop for all their safety and survival needs. The Survitec MES system provide high capacity transfer from deck side to sea without the need to enter the water and unlike similar systems currently available offers a single high capacity life raft that sits below the chute column and requires no additional life rafts. Once all evacuees have descended the chute and entered the high capacity raft, the raft is disconnected and floats free awaiting recovery.

This eradicates the need for cross boarding from a self-inflated boarding raft to additional rafts and therefore significantly reduces the risk of being washed overboard whilst cross boarding is taking place, this also serves to reduce the evacuation times as cross boarding is no longer required.

For details contact: Survitec Group Ltd Intl House, George Curl Way, Southampton, Hampshire SO18 2RZ. U.K. Tel: +44 (0)23 8030 2020, Fax: +44 (0)23 8030 2177 E-mail: info@survitecgroup.com

For details contact: LANXESS india Pvt Ltd LANXESS House, Plot No: A 162-164, Road No: 27, MIDC Wagle Estate, Thane (W), Maharashtra 400 604 Tel: 022-25871000 , Telefax: 91-022-25836742 E-mail: rhituparna.mitra@lanxess.com

LPG GAS ROASTER INFRARED GAS LEAK DETECTOR (IR-5000) IR point sensors use radiation passing through a volume of gas to detect leaks. Energy from the radiation is absorbed as it passes through the gas at certain wavelengths. Carbon monoxide absorbs wavelengths of about 4.2-4.5 μm. This is approx a factor of 10 larger than the wavelength of visible light, which ranges from .39 to .75 μm for most. The energy in this wavelength is compared to a wavelength outside of the absorption range; the difference in energy betweven these two wavelengths is proportional to the concentration of gas present. IR point sensors can be used to detect hydrocarbons, compounds composed of hydrogen and carbon atoms, and other IR active gases. IR sensors is commonly found in wastewater treatment facilities, refineries, chemical plants, and other facilities where flammable gases are present and the possibility of an explosion exists.

For details contact: Ambetronics Engineers Pvt Ltd 17-B Tarun Indl Estate, New Nagardas Road, Andheri (E), Mumbai 400 069 Tel. 022-66995525, 28371143 www.oswindia.com

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Fans Bro Erectors offers roaster machine with LPG/CNG gas heating arrangements. It has all the advantages which electrically operated roaster machine has, such as auto electronic operating, temperature controlling system, etc.

The heating temperature can be achieved easily in a short time up to 350 oC, which is achieved with hot generated air circulation through specially designed heating jacket.

The LPG gas roaster machine can be used to roast various types of powders, flours, seeds, but ideal for grains, pulses, seed type products with hard outer shell. The LPG gas roaster machine is available in capacities ranging from 200 to 5,000 litres or more size machines can be fabricated as per customer requirements in complete SS (GMP Model) or as contact parts in SS (Standard Model) construction.

For details contact: Fans Bro Erectors No: 401, Plot No: 74, Shubh Ashirwad Jay Prakash Nagar, Road No: 5, Goregaon (E), Mumbai 400 063

Offshore World | 48 | AUGUST - SEPTEMBER 2013

04-10-2013 15:09:08

PORTABLE LPG DENSITY METERS

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Unique laboratory density meter is a new development especially for LPG measuring.

It is based on the resonant method of density measurements and uses small sample volume. Obtained results are instantly converted to relative density (15째C or 20째C or 60째F) in accordance with ASTM D1250 tables. Readings on the LCD facilitate measuring process and eliminate eventual human error.

Combination with PC or pocket PC makes it as a complete data managing system. Windows-based software allows necessary data processing and simplifies operation for personnel.

Rohan BRC Gas Equipment Pvt Ltd offers high quality range of LPG reducer manufactured by experts, who have immense experience in this field. These products have sturdy construction and are able to give efficient performance.

For details contact: Lemis India Pvt Ltd No: 603, Platinum Techno Park Plot No: 17/18, Sector 30-A, Vashi Navi Mumbai 400 703 Tel: 022-67215655, Fax: 91-022-67942666

LPG GAS DETEC TOR Power Plus India Ent offers range of LPG gas detector using superior grade component and advanced technology. Their range is known for their extraordinary capability to track down the LPG, propane and butane natural gases. These detectors possess a semiconductor sensor technology and are applicable in different areas.

LPG FLOW METERS From a range of flow metering technologies available Cosmic Technologies offer the best solution as per the specific demands of ones application. Many years of experience helps them select just the right system for LPG flow ;measurement, be it low cost volumetric flow monitoring application or applications demanding precision density compensated totalisation. Their differential pressure based flow measurement systems follow international standards like ISO 5167 which means that time tested technologies like orifice plates, venturis, flow nozzles, pitot tubes, etc, deliver predictable and accurate metering results.

Their system can easily be interfaced to SCADA or DCS systems as various options like analog retransmission and RS485-MODBUS outputs are available.

For details contact: Cosmic Technologies Plot No: 87, Indl Area, Phase 9 Mohali, Punjab 160 062 Tel: 0172-5096230 E-mail: vikram@cosmictechNo:com / info@cosmictechNo:com

For details contact: Rohan BRC Gas Equipment Pvt Ltd 5, Ashwamegh, Indl Estate, Changodar Taluka - Sanand, Ahmedabad, Gujarat 382 213 Tel: 02717-251900, Fax: 91-02717-251702

For details contact: Power Plus India Ent 2, 2nd Floor, Orchid Mall Nr Govardhan Party Plot Thaltej Shilaj Road, Thaltej Ahmedabad, Gujarat 380 059 Tel: 079-32425236

LPG VAPORIZER Chandra Engg & Mechanical offers technically advanced range of LPG vaporizer that is durable in nature and is quality approved. Their entire product range is used in varied industrial applications and is delivered in standard sizes. Their professionals manufacture the entire product range using modern techniques and tools.

For details contact: Chandra Engg & Mechanical 103 Devji Keshavji I. E, Wamanrao Patil Marg, Opp: Durkes Factory, Chembur, Mumbai Tel: 022-25204192, 25200233, 25200232, Fax: 91-022-25204006, 25500235

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products

DRILLING RIG Paranthaman Exporters offers wide range of prd oz drill, which is powered by truck engine or separate deck engine. Based on latest technology, these drills are used to drill water wells, oil wells or natural gas extraction wells. The rotation with direct circulation ensures that the drilling is done properly.

For details contact: Paranthaman Exporters (Export Unit of PRD Rigs India) Plot No: M-8, SIPCOT. SEZ for Engg Products Perundurai, Tamil Nadu 638 052 Tel: 04294-234481, 234482, 234483, Fax:91-04294-234484 E-mail: myrig@prdrigs.com / paran@prdrigs.com / marketing@prdrigs.com

DRILLING RIGS A drilling rig is a machine which creates holes in the ground. Drilling rigs can be massive structures housing equipment used to drill water wells, oil wells or natural gas extraction wells, or they can be small enough to be moved manually by one person.

For details contact: Royal Exim 10/1, Kammamahalli Main Road, Nr Kullappa Circle Bengaluru, Karnataka 560 033

PNEUMATIC MAGNETIC DRILLING MACHINE The Air 52 pneumatic magnetic drilling machine is intended for operations in environments with explosion hazards, eg, offshore, petrochemical industry, oil and gas extraction, energy plants as well as ship building and naval industry.

For details contact: Chekov Hydraulics No: 511, Lalita Towers, Nr Rajpath Hotel, Alkapuri Vadodara, Gujarat 390 007 Tel: 0265-2320081, 3054225 www.oswindia.com

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SIMBA JUNIOR AUTOMATED DRILLING RIG Mindrill Systems & Solutions Pvt Ltd offers both manual as well as automated drilling rigs. In their broad array, Mindrill Systems & Solutions Pvt Ltd offer Simba Junior Remote Control.

The drilling rigs are extensively used in digging water, gas or oil wells.

Their expert quality engineers use stringent tests during each stage of tools manufacturing to ensure total compliance of industry set norms.

Drilling equipment of theirs finds extensive application in water and oil exploration works.

For details contact: Mindrill Systems & Solutions Pvt Ltd 50/C/1 A, K G Bose Sarani, Kolkata 700 085 Tel: 033-23510226, 26539638 Fax: 91-033-23514643

REVERSE CIRCULATION DRILLING RIGS Super Engineers offers wide range of reverse circulation drill rig made up of premium grade raw material. These machines are multi-purpose machines and are highly efficient as well. The use of latest foreign gas lift reverse circulation drilling technology is used so that the dust can be effectively accumulated by the collector to avoid environmental pollution. These are very efficient for drilling wells, monitoring wells, ground source heat pump air-conditioning and other deep hole of choice for equipment. These can be applicable in different formation on the compressed air reverse circulation drilling DTH. For details contact: Super Engineers Chandigarh Road, Baldev Nagar Ambala, Haryana 134 007 Tel: 0171-2540962, 2540574, 2543063 Fax: 91-0171-2540798 E-mail: super@superengineers.com / balbirsingh_63@yahoo.in

Offshore World | 50 | AUGUST - SEPTEMBER 2013

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project update

Media Barter with gulfoilandgas.com

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

Project

Country

Value ($)

Status

Bahrain Refinery Expansion

Bahrain

6,500,000,000

Bidding

Yateem Oxygen - Carbon Dioxide Extraction Plant

Bahrain

-

Execution

Daura Refinery - Fluid Catalyst Cracking (FCC) Unit

Iraq

2,500,000,000

Bidding

Karbala Refinery

Iraq

4,000,000,000

Bidding

Nasiriyah Grassroots Refinery

Iraq

8,000,000,000

Bidding

New Karbala Refinery

Iraq

6,500,000,000

Study

Al Zour Refinery

Kuwait

190,000,000

Bidding

Clean Fuels Project (CFP)

Kuwait

18,500,000,000

Execution

Sohar PTA Plant

Oman

680,000,000

Execution

Sohar Refinery Expansion

Oman

1,500,000,000

Bidding

Yibal Depletion Compression - Phase III

Oman

-

Execution

QAFAC - Carbon Dioxide (C02) Recovery Plant

Qatar

80,000,000

Execution

QP/Qapco Al Sejeel Petrochemical Complex Development

Qatar

7,400,000,000

FEED

QP/Shell - Ras Laffan Olefins Complex

Qatar

6,400,000,000

FEED

Aramco/Dow Jubail Petrochemicals Complex - Propylene Oxide Unit

Saudi Arabia

-

Execution

Jazan Export Refinery

Saudi Arabia

7,000,000,000

Execution

Ras Tanura Refinery - Clean Fuels & Aromatics Project

Saudi Arabia

3,000,000,000

Bidding

SATORP - Jubail Export Refinery

Saudi Arabia

9,600,000,000

Execution

Chemaweyaat - Taweelah Petrochemicals Complex Phase 1

UAE

10,000,000,000

FEED

IPIC - New Fujairah Oil Refinery

UAE

3,500,000,000

FEED

Ruwais Refinery New Facilities

UAE

500,000,000

Execution

Socar - Aurora Fujairah Storage Terminal Development Africa

UAE

180,000,000

Execution

Africa

Country

Value ($)

Status

Algiers Refinery Revamping

Algeria

300,000,000

Execution

Skikda Refinery Upgrade

Algeria

2,600,000,000

Execution

Lobito (SonaRef ) Refinery

Angola

8,000,000,000

Execution

Soyo Refinery

Angola

-

Planning

Cameroon Ammonia Urea Fertilizer Plant

Cameroon

1,400,000

Study

Alexandria Petrochemicals Complex - Polyethylene Plant

Egypt

-

Execution

Middle East

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Africa

Country

Value ($)

Status

ERC - Mostorod Refinery

Egypt

3,700,000,000

Execution

E-Styrenics Polystyrene Plant

Egypt

758,000,000

Execution

Suez Tank Terminal

Egypt

-

Study

Tahrir Petrochemicals Complex [NEW]

Egypt

3,700,000,000

Study

Port-Gentil Refinery [NEW]

Gabon

1,000,000,000

Planning

Tema Fuel Storage Tanks

Ghana

-

Study

Mbini Refinery

Guinea

404,000,000

Execution

Kenya Petroleum Refineries Limited (KPRL) Mombasa Refinery

Kenya

17,000,000

Execution

Mellitah Complex

Libya

-

Execution

OCP-Diammonium Phosphate Facilities

Morocco

170,000,000

FEED

Zinder Refinery (Soraz)

Niger

980,000,000

Execution

Akabuyo Refinery

Nigeria

7,500,000,000

Planning

Eleme Fertilizer Plant

Nigeria

1,200,000,000

Execution

Coega (Mthombo) Refinery

South Africa

10,000,000,000

FEED

Mnazi Ammonia/Urea/Methanol Project

Tanzania

-

Study

Hoima Oil Refinery

Uganda

2,500,000,000

Study

Caspian Region

Country

Value ($)

Status

Azerikimya Ethylene-Polyethylene Plant

Azerbaijan

-

Execution

Oil, Gas Processing & Petrochemical Complex (OGPC) Project

Azerbaijan

15,000,000,000

Study

Sumgayit Nitrogen Fertilizer-Urea Complex

Azerbaijan

-

Study

Abadan Refinery Upgrade

Iran

3,000,000,000

Execution

Bandar Imam Petrochemical Complex

Iran

-

Execution

Esfahan (Isfahan) Refinery Expansion

Iran

2,500,000,000

Execution

Ham - Petrochemicals Complex (Olefins 13)

Iran

-

Execution

Imam Khamenei Gas Refinery

Iran

-

Study

Karoon Isocyanates Complex

Iran

-

Execution

Lavan Refinery Upgrade

Iran

-

Execution

Parsian Gas Refinery

Iran

400,000,000

Execution

Persian Gulf Star Gas Condensate Refinery (PGSCR)

Iran

2,600,000,000

Execution

Tabriz Refinery Expansion (Shahriar Refinery)

Iran

2,000,000,000

Execution

Atyrau Petrochemical Complex

Kazakhstan

5,200,000,000

Execution

Atyrau Refinery Upgrade

Kazakhstan

1,040,000,000

Execution

Karachaganak Gas Refinery

Kazakhstan

3,700,000,000

Study

Antipinsky Oil Refinery

Russia

135,664,000

Execution

Far Eastern Petrochemical Company Construction (FEPCO) Projecl

Russia

5,000,000,000

Study

FEPCO Project

Russia

5,000,000,000

Study

Moscow Refinery Upgrade

Russia

-

Execution

Omsk Refinery Upgrade

Russia

5,000,000,000

Execution

Togliatti Ammonia and Hydrogen Plant

Russia

350,000,000

Study

www.oswindia.com

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events diary 3 rd SUBSEA INDIA 2013

Oil & Gas World Expo 2014

Date: 4-5 December 2013 Venue: Imperial Hotel, Janpath, New Delhi, India Event: The Third SUBSEA INDIA 2013 Conference and Exhibition will focus on “Subsea/Deepwater and Offshore Technology and Services.

The Third SUBSEA INDIA 2013 will be attended by the officials from the Ministry of Petroleum and Natural Gas, Government of India along with senior executives, decision makers and experts of national and international oil companies and service providers. Connect with some of the world’s most renowned figures in the industry. Experts from India, US, UK, Norway, China, Malaysia, Singapore, UAE and Australia are to attend the conference.

The conference besides focusing on the theme will have a high powered CEO PANEL comprising CEO’s from operator/service provider companies of the oil and gas industry. This year the CEO Panel will be Chaired by Mr.Sudhir Vasudeva, Chairman & Managing Director, Oil & Natural Gas Corporation Limited and Chairman, ONGC Group of Companies. The CEO Panel will comprise of five leaders of the industry discussing on the issues related to the subsea, deepwater and offshore segment of the industry.

For details contact: DEW SYMPOSIUMS Tel: +91-9837038270, +91-135-2740559 E-mail: info@dewsymposiums.com PETROTECH-2014 Date: January 12-15, 2014 Venue: India Exposition Mart Limited, Greater Noida, Delhi (NCR) Event: The PETROTECH series of International Oil & Gas Conference and Exhibitions is a biennial platform for national and international experts in the oil & gas industry to exchange views and share knowledge, expertise and experiences.

The event also aims to explore areas of growth in petroleum technology, exploration, drilling, production and processing, refining, pipeline, transportation, petrochemicals, natural gas, LNG, petroleum trade, economics, legal and human resource development, marketing, research & development, information technology, safety, health and environment management in the oil & gas sector. As the prime showcase of India’s hydrocarbon sector, this mega event attracts scientists, technologists, planners and policy makers, management experts and entrepreneurs to solicit their views in order to catalyse achievement of global energy security. PETROTECH-2014 is being organized under the aegis of the Ministry of Petroleum & Natural Gas, Government of India, by Oil and Natural gas Corporation Limited and PETROTECH. For details contact: PETROTECH-2014 Secretariat Oil & Natural Gas Corporation Ltd Jeevan Bharati, Tower - II, Indira Chowk, New Delhi - 110001 (INDIA) Tel.: +91-11-23312607/ 23301169/ 23301170 , Fax: +91-11-23315207 Email: secretariat@petrotech.in

Date: February 10-12, 2014 Venue: Bombay Exhibition Centre, NSE Complex, Goregaon, Mumbai, India Event: Oil & Gas World Expo 2014, the 6 th International Exhibition & Conferences, scheduled in 10-12 February, 2014, will organise by CHEMTECH Secretariat and supported by CHEMTECH Foundation, who are pioneers in conceiving international Exhibitions and Conferences since 1975.

For the entire ‘Upstream’ value chain related to Oil & Gas exploration, production and transportation, the expo will provide a platform to showcase India’s growing engineering and technological capabilities in the entire upstream hydrocarbon value chain. The increasing number of exhibitors since its first edition in 2004 reflect India’s growing role in the global hydrocarbon sector.

For details contact: Chemtech Secretariat 26, Maker Chambers VI, Nariman Point, Mumbai 400 021, India Tel: +91-22-40373737 Fax: +91-22-22870502 Email: conferences@jasubhai.com Offshore Energy Exhibition and Conference 2014 Date: 28-29 October 2014 Venue: Amsterdam RAI, the Netherlands Event: The 7 th edition of Offshore Energy conference will host between 500 and 600 exhibitors and is expected to attract over 10,000 professionals from all over the world. Both the exhibition and the extensive conference program of Offshore Energy 2014 will address the technical, operational and commercial challenges associated with industry growth.

The 2014 technical program will once again feature an international faculty of speakers covering a broad palette of topics. Meetings range from high caliber panels and technical sessions to annual meetings of industry organizations and masterclasses, catering to professionals from board level to operational level and young talents.

For details contact: NAVINGO BV Westerlaan 1 3016CK Rotterdam The Netherlands Tel: +31 (0)10 2092600 Fax: +31 (0)10 4368134 Email: me@navingo.com

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book shelf SUBSEA ENGINEERING HANDBOOK Authors: Yong Bai & Qiang Bai Price: $147.94 Paperback: 960 pages Publisher: Gulf Professional Publishing Book Description: D esigning and building structures that will withstand the unique challenges that exist in Subsea operations is no easy task. As deepwater wells are drilled to greater depths, engineers are confronted with a new set problems such as water depth, weather conditions, ocean currents, equipment reliability, and well accessibility, to name just a few. A definitive reference for engineers designing, analyzing and instilling offshore structures, Subsea Structural Engineering Handbook provides an expert guide to the key processes, technologies and equipment that comprise contemporary offshore structures.

Written in a clear and easy to understand language, the book is based on the authors 30 years of experience in the design, analysis and instillation of offshore structures. This book answers the above mentioned crucial questions as well as covers the entire spectrum of subjects in the discipline, from route selection and planning to design, construction, installation, materials and corrosion, inspection, welding, repair, risk assessment, and applicable design solutions. It yields a roadmap not only for the subsea engineer but also the project managers, estimators and regulatory personnel hoping to gain an appreciation of the overall issues and directed approaches to subsea engineering design solutions.

D E E P WAT E R H O R I Z O N O I L S P I L L A N D R E L AT E D I S S U E S ( E N V I R O N M E N TA L S C I E N C E , E N G I N E E R I N G A N D T E C H N O LO G Y ) Editors: Danielle M. Birkin; Editor: Jonathan J Asher Price: $170.00 Paperback: 224 pages Publisher: Nova Science Publishers Book Description: TIn 20 April 2010, an explosion of fire occurred on the Deepwater Horizon drilling rig in the Gulf of Mexico.

This resulted in eleven worker fatalities, a massive oil release and a national response effort in the Gulf of Mexico region by the federal and state governments. This book explores the issues that have arisen from this crisis, as well as how the spill affects the national energy policy, and the trade-offs between energy needs, risks of deepwater drilling and protection of natural resources and amenities. www.oswindia.com

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OIL AND GAS: INTERIOR HAS STRENGTHENED ITS OVERSIGHT OF SUBSEA WELL CONTAINMENT, BUT SHOULD IMPROVE ITS DOCUMENTATION Author: Government Accountability Office Price: $15.19 Paperback: 40 pages Publisher: CreateSpace Independent Publishing Platform Book Description: According to a 2010 Interior study, 97 percent of oil and gas production in federal waters occurs along the U.S. outer continental shelf of the Gulf of Mexico.

The outer continental shelf is the submerged lands outside the territorial jurisdiction of all 50 states but within U.S. jurisdiction and control.5 The outer continental shelf contains an estimated 85 billion barrels of oil, and over half of this oil is located in the Gulf of Mexico. Significant reser ves also exist in the outer continental shelf off Alaska.

NATURAL GAS HYDRATE - ARCTIC OCEAN DEEPWATER RESOURCE POTENTIAL Authors: Michael D Max, Arthur H Johnson and William P. Dillon Price: $43.30 Pages: 40 pages Publisher: Springer Book Description: The book is an up-to-date basic reference for natural gas hydrate (NGH) in the Arctic Ocean. Geographical, geological, environmental, energy, new technology, and regulatory matters are discussed. The book should be of interest to general readers and scientists and students as well as industry and government agencies concerned with energy and ocean management.

NGH is a solid crystalline material that compresses gas by about a factor of about 164 during crystallization from natural gas (mainly methane) - rich pore waters over time. NGH displaces water and may form large concentrations in sediment pore space. Its formation introduces changes in the geotechnical character of host sediment that allows it to be distinguished by seismic and electric exploration methods. The chemical reaction that forms NGH from gas and water molecules is highly reversible, which allows controlled conversion of the NGH to its constituent gas and water.

This can be achieved rapidly by one of a number of processes including heating, depressurization, inhibitor injection, dissolution, and molecular replacement.

The produced gas has the potential to make NGH a valuable unconventional natural gas resource, and perhaps the largest on earth.

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Offshore World | 55 | JUNE - JULY 2013

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

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