new base special 04 may 2014

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NewBase 04 May 2014 Khaled Al Awadi

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Masdar-backed wind farm set to start ops in Q1 2015 By Arabian Business , Andy Sambidge

The Middle East's first wind power project, in which the UAE's Masdar holds a 31 percent stake, will start to deliver electricity in the first quarter of 2015, it has been announced. Jordan Wind Project Company, which is a co-development between InfraMed, Masdar and EP Global Energy, is behind the

117MW Tafila Wind Farm which will increase Jordan's total power capacity by three percent and will cost about $290m to build.

A statement said civil works have already begun, and the 38 wind turbines will be directly transported from the port of Aqaba to the project site over the coming months. The first turbines will begin to produce electricity as from the first quarter of 2015, and the wind power plant will be fully operational by August 2015.

The wind power plant will then be connected directly to the National Electric Power Company

grid and provide almost 400 GWh of electricity per year, enough to meet the energy needs of over 150,000 Jordanians. The Al Tafilah project will also significantly contribute to the region's development by providing jobs to 150 people during construction and 30 during its operation, the statement added.

Samer Judeh, chairman of JWPC, said: "At 85 Jordanian Dinars per MWh, electricity is priced at less than half the cost of generation from conventional power. The price is fixed for 20 years, ensuring reliable and clean energy for the country. "The Tafilah wind farm is a major step towards getting Jordan on the global renewable energy roadmap and will serve to demonstrate the region's potential for investments in renewable energy.

With Jordan's electricity demand expected to grow by an estimated 5 percent annually until 2020, the country is rapidly developing new sources of energy generation to avoid future shortfalls. Tafila is the first wind-power project to be developed under Jordan's Renewable and Energy Efficiency Law passed in 2010.

The law calls for the country to obtain seven percent of its electricity from renewable energy sources by 2015, rising to 10 percent by 2020.




UAE–QATAR Dolphine Gas Compression on track for completion Source : Mubadala

An expansion of the Qatar-UAE gas pipeline is on track to be completed by the end of the year despite the lack of a deal for extra fuel, said Mubadala Petroleum, its majority shareholder. Work began last year on a US$250 million upgrade to the Dolphin Pipeline’s gas compression facilities, which would allow Qatar to export the full 3.2 billion standard cubic feet that the pipeline was built to accommodate. A little over 2 billion scf is flowing to the UAE from Qatar via the Dolphin gas project today.

The continued work on the expansion indicates hopes for continued cooperation with Qatar even as a diplomatic spat hinders cross-border business. Earlier this year, Dubai-based Danube put on hold a Dh 30m retail unit there, citing an uncertain investment climate, and Qatar Petroleum was reported to have backed away from partners Mubadala Petroleum and Oman Oil in bidding for Occidental Petroleum’s Middle East assets.

“By the end of this year Dolphin is going to have the ability to push a lot more gas,” said Maurizio La Noce, the chief executive of Mubadala Petroleum. “When and if and how that gas is going to come, I don’t know. For us it’s important to have the availability of the capacity, and then it’s going to be between the Qatari authorities to determine.”




Mr La Noce, whose company owns 51 per cent of Dolphin alongside Total and Occidental, declined to comment on Occidental’s prospective sale of regional assets. Up to 40 per cent of the American producer’s assets, including the sole rights to two oilfields in Abu Dhabi and a concession for Abu Dhabi’s Shah sour gasfield, are on the auction block.

In separate comments at an industry event in Dubai, he said he regretted not securing more gas from Qatar in 1999. Then Qatar had not yet become an LNG king, and Abu Dhabi’s gas demands were in check. Today the gas from the contract is at a substantial discount to what Abu Dhabi would pay to import or develop technically challenging projects like Shah or the recently awarded Bab sour gasfield.

“Instead of contracting 2 billion scf of gas for Dolphin, we had the opportunity to do 3,” said Mr La Noce. “At the time, it was 1999. Even the 2 [million scf], everybody was telling me, ‘You can’t sell all this gas.’”

Mubadala Petroleum is also hammering out ways to cooperate with Adnoc in unconventional technology as well as research and development, part of an agreement signed late last year.

In the long term, Mubadala may bid for the rights to develop small fields that would otherwise pass unnoticed by Adnoc.

“They’re about to produce 3 million barrels a day,” said Mr La Noce. “For them to look at a field that may produce only 10,000 or 20,000 barrels a day, frankly speaking, it’s going to be tough. But that could in the future open up for a company like us to leverage what we know and produce 20,000 barrels a day, because we are a low-cost producer. Something like that wouldn’t move the needle of Adnoc or Exxon, but it moves the needle for us.”

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Gas production on track to meet Oman’s rising demand BYTIMES NEWS SERVICE - OMAN

Domestic gas requirements are set to expand rapidly over the next few years as Oman's industrial base expands and as the utilities sector grows to keep pace with rising demand for water and electricity. However, officials have said projected increases in gas production will be managed to ensure supplies can be guaranteed over the long term. The Oman Power and Water Procurement Company (OPWP) estimates gas consumption in the electricity and water desalination sector will rise from the current annual volume of 6.7 billion cubic metres to 10 billion cubic metres by 2020, an almost 50 per cent increase. While the national demand for gas will rise sharply over the coming six years, the rate of increase is by no means evenly distributed, with requirements set to spike in some regions. This is particularly the case in areas of the country where the government has promoted industrialisation as a means to broaden the economic base and provide new opportunities. Demand for gas in the Salalah region, the centre of extensive industrial development, is forecast by the OPWP to rise from the current 0.72 billion cubic metres annually to 1.2 billion by 2020 as new industrial facilities, as well as the power plants and utilities needed to support them and the swelling population, come on-line.

Pumping up the volume To help meet this demand from the utilities sector, along with that of industry and private consumers, Oman is pushing to raise production, with output to be increased steadily over the next few years. Production from domestic fields, which topped 100 million cubic metres a day in 2013, should reach 120 million cubic metres a day by 2018, according to the Ministry of Oil and Gas.




The biggest boost to output, one that could push production past the daily figure of 120 million cubic metres, will be the new Khazzan-Makarem tight gas development. A project of energy major BP and the Oman Oil Company Exploration and Production, the Khazzan project is based in an area known as Block 61 in central Oman. By sinking some 300 wells to depths of up to 4500 metres and utilising hydraulic fracturing technology and other techniques, BP plans to produce 28.3 million cubic metres of gas a day. According to Dave Campbell, BP Oman's general manager and vice-president of operations, Khazzan will be a significant factor for the economy of Oman. "BP and its partner are making a $16 billion investment in developing the Khazzan tight gas resource," he told OBG. "This project is not only important for BP, but is essential for the Sultanate of Oman. The economic benefit of gas extends past the energy sector because the growth in the supply of energy for Oman is also an enabler for economic development in all other sectors," he added. Prioritising demands While Oman will have far greater access to gas supplies in the coming years, the government intends to manage upstream flow to downstream industries, balancing long-term supplies with measured industrial expansion. According to Salim bin Nasser Al Aufi, the undersecretary of the Ministry of Oil and Gas, the first priority for the increased flow of gas will be utilities, ensuring the supply of electricity and water (through desalination), with commitments to existing industries being met after that. "Yes, we will have more gas, but if we produce all of it today, then very soon in the future we will have a big hole," Al Aufi told local media in late March. "When Khazzan-Makarem kicks in, there will be other producers and we will need to turn them down a little bit, so that we save that gas for the future." One of the industry players already set to benefit from rising gas production is Sohar-based Jindal Shadeed Iron and Steel with its recently expanded production facility set to take annual output of steel products to around 2.0 million tonnes, most of which will be destined for the growing domestic market. Naushad Ansari, Jindal Shadeed's director and head of plant, recently told OBG, "Heavy industry forecasts expansion and operations based on the availability of gas, therefore it is crucial that the country's strategy going forward revolves around ensuring reliable gas feedstock to industrial estates."




TPAO and Kuwait Energy to award Iraq Mansuriya Project soon The Houston-based engineering company KBR is currently completing the front end engineering and design (FEED) for the gas treatment facilities to be built at the Mansuriya gas field in the Diyala region of East Iraq by a joint venture led by Turkish Petroleum Corporation (TPAO), through its subsidiary Turkish Petroleum Overseas Company (TPOC), in partnership with the local Midland Oil Company (Midland Oil), Kuwait Energy Corporation (KEC), the Korean Gas Corporation (Kogas).

Located 110 kilometers northeast of Baghdad near the Iran boarder, the Mansuriya gas field is the second largest non-associated gas field in the Diyala Region.

Covering 110 square kilometers, Mansuriya is estimated to hold 4.5 trillion cubic meters of non-associated gas and condensate.

Discovered in 1978, the Mansuriya gas field has been left undeveloped since then and up to the bidding round organized by the Iraq Government for the Energy Development program.

Before the wars and even more after the wars, Iraq has been over producing gas country wise compared to its domestic needs.

But of the gas produced was generated as associated gas and concentrated in the south and the north of Iraq.

Because of the lack of transportation infrastructures, this gas could not be exported from one region to another so that most of it was just flared in-place.

Large programs are on going to gather and monetize the flared gas, but in the meantime the regions in the center, east and west of Iraq still need gas to feed power generation and economical development;

KBR completes FEED on Mansuriya gas plant project In October 2010, TPAO and its partners Midland Oil, KEC and Kogas were awarded the Mansuriya gas field during the Third Bidding Round proposed by Iraq Government.

As a result, TPAO and its partners signed a Development and Production Service Agreement for a period of 20 years on Mansuriya.

In Mansuriya, TPAO is sharing the working interests as following:

- TPAO 37.5% is the operator




- KEC 22.5% - Kogas 15% - Midland Oil 25% During the twenty years of Service Agreement, TPAO and its partners are planning to extract from Mansuriya:

- 47.6 billion cubic meters of gas - 143.6 million barrels of condensate As part of Iraq Energy Development program the gas will supply a power plant and the condensate the local industries. In December 2012, TPAO and its partners KEC, Kogas and Midland Oil, awarded the FEED contract for the Mansuriya gas field development project. In addition to the FEED contract KBR will provide Quality Control Support Services (QCSS) during the engineering, procurement and construction (EPC) phase of the project;

Based on the FEED proposed by KBR, the Mansuriya project should include:

- Gas gathering system - Gas and condensate separation - Gas sweetening and regeneration unit - Gas dehydration and regeneration unit KBR designed the Mansuriya gas treatment facilities with a capacity of 110 million cubic feet per day (cf/d) of gas.

As KBR is completing the FEED, TPAO and its partners Kuwait Energy, Midland Oil and Kogas are expected the award the EPC contract for the Mansuriya gas central processing plant on the second quarter 2014 for a first production in 2016.




Asian coal curves shift to contango offer price hope By Reuters Clyde Russell

There is a glimmer of hope for Asian coal miners with the forward curves for various grades of the fuel starting to point to higher prices in the second half of the year.

The price of spot coal at Australia’s Newcastle Port, an Asian benchmark, was $73.12 a tonne in the week to April 25, down about 15% so far this year and close to the four-and-a-half-year low of $72.98 hit in March.

But while spot coal has been weakening for the past few months, the shape of the futures curve has gradually been shifting to contango, where the price for further-out months exceeds that for near-month contracts.

The front-month Newcastle coal contract traded on ICE Futures Europe was at a discount of 3.9% to the six-month contract on Thursday. Three months ago the curve was in backwardation, with the front-month at a 3.4% premium to the six-month.

The shift to contango would normally be taken as a bullish indicator that prices are more likely to increase in coming months than decline. But it’s not just the thinly-traded Newcastle futures that have flipped to contango. The Indonesian sub-bituminous strip, which tracks prices of low-rank coal, has also switched in the past three months.

The front-month contract was at a 0.8% discount to the six-month on Thursday, while three months ago the front-month was at a 4.1% premium to the six-month. The Argus API8 contract, which measures the price of 5,500 kilocalorie coal delivered to south China, is still in mild backwardation on the front-month to six-month spread, although it has shifted to contango from the seventh month onwards.




The front-month API8 was at a premium of 0.5% to the six-month on Thursday, whereas three months ago the premium was 5.2%. What the curves are showing is that the market is no longer anticipating that coal prices will continue to fall, although the mild contango certainly isn’t suggesting much of a rally. For prices to recover it would take some re-alignment of the supply-demand balance, currently characterised by plenty of supply meeting only modest growth in demand.

The response of many producers in Australia and Indonesia, the world’s top two coal exporters, to low prices has been to boost output in the hope of lowering unit costs per tonne mined, thereby boosting profitability.

The problem with this tactic is that while it may work for a single miner or even a small number of miners, when everybody is doing it, supply swamps the market, pushing prices lower and quickly eroding any productivity gains. Thus the coal market remains over-supplied, even at the current low prices. For prices to gain, it would take an uptick in demand, and here the outlook may be somewhat brighter.

Demand in top importer China may increase in the second half, in line with expected stronger economic growth.

Domestic coal prices at Qinhuangdao increased slightly in April to around 535 yuan ($85.48) a tonne, up from levels around 520 yuan in March, and port inventories were reported to have fallen.

A change to tax on domestic output from a volume to a price basis may boost China’s coal prices by between 11 and 55 yuan a tonne, which in turn would allow the price of imports to rise in tandem.

A drive to lower pollution from burning coal won’t necessarily result in less of the fuel being consumed. It may instead result in better quality coal being used, and more of it, especially if the more modern generators start using scrubbers rather than leaving the air-cleaning units turned off. Demand outside China also looks like it is improving, with India, Japan and South Korea all importing more coal, given it is currently much cheaper than alternatives such as natural gas or oil for power generation.

However, the sheer volume of coal available on the seaborne market will likely exceed any demand gains, meaning that price rallies are unlikely to be sustained. Even so, the shift of forward curves to mild contango indicates that prices may have bottomed out at the recent lows.




Norway: Statoil announces oil and gas discovery in the Barents Sea Source: Statoil

Operator Statoil has together with PL532 partners has made an oil and gas discovery in the Drivis Prospect in the Barents Sea. This concludes the 2013/2014 exploration programme around the Johan Castberg field. Well 7220/7-3 S, drilled by the rig West Hercules, has proven a 68 metre gross gas column in the Stø formation and an 86 metre gross oil column in the Stø and Nordmela formations. Statoil estimates the total volumes in Drivis to be in the range of 44-63 million barrels of recoverable oil equivalent (o.e.), out of which 42-54 million barrels of oil.

In May 2013 Statoil launched a targeted exploration campaign around the Johan Castberg field in order to clarify additional oil potential in the area and make the development project more robust. The exploration campaign comprised five wells and has lasted for 12 months. Drivis was the last well of this drilling campaign in the Johan Castberg area.

'Over the past year we have made a significant exploration effort in the Johan Castberg area. Five wells have been drilled back-to-back, giving us important subsurface information and a good understanding of the total resource base in the area', says Irene Rummelhoff, Statoil senior vice president for exploration on the Norwegian continental shelf. 'We are certainly glad to have an

oil discovery in Drivis. However, the exploration programme as a whole has not delivered on volume expectations. Out of the five wells drilled only two have resulted in oil discoveries,' says Rummelhoff.

The exploration results constitute an important input to the Johan Castberg field development project.

'We will now work closely with our licence partners to analyse the findings of the exploration programme and what those mean for the Johan Castberg development project,' says Erik Strand Tellefsen, Statoil vice president for field development northern Norway.

Statoil is operator for production licence PL532 with an ownership share of 50%. The licence partners are Eni Norge (30%) and Petoro (20%).

For further details on the results of exploration well 7220/7-3 S, see the press release issued by the Norwegian Petroleum Directorate (NPD)




Shell joins SCCS JIP that aims to extend life of North Sea oil fields Press Release, Shell

A joint industry project to investigate mechanisms for creating a CO₂-driven enhanced oil

recovery (CO₂-EOR) industry in the North Sea has welcomed Shell as a new industry partner.

CO₂-EOR has the potential to bring benefits for the UK offshore industry by improving recovery

from depleted oil fields using CO₂ captured from power plants and industry.

Shell joins project leader, Scottish Carbon Capture & Storage, and its existing JIP partners, the Scottish Government, Scottish Enterprise, 2Co Energy and Nexen Petroleum UK Ltd, as a second phase of research gets under way.

The project is focused on gaining a better understanding of the use of CO₂ in EOR operations, with the aim of extending the life of North Sea oil fields using CO₂ captured from large emitters – such as power plants and industrial facilities – and permanently storing the greenhouse gas in offshore oil reservoirs.

The first phase of research has investigated issues that could affect the development of CO₂-EOR linked with CCS projects, such as the legal and regulatory frameworks and taxation. Various fiscal models are being explored, alongside an investigation of how CO₂-EOR is perceived by government, regulators, NGOs, the public and other stakeholders.

The project partners will now focus on a range of research, including reservoir modelling, further analysis of fiscal arrangements and the carbon balance of CO₂-EOR operations, as well as public engagement.

SCCS Director, Prof. Stuart Haszeldine, said: “We are delighted to welcome Shell to the project as we

move into a second phase of research. Not only are they global leaders in CCS development, but they will

also bring unrivalled technical capabilities and understanding to the JIP through their oil and gas

expertise, especially in the North Sea. This will enable us to significantly build on learnings from the first

phase of the project.”




LR Senergy calls for solutions to drilling challenges Press Release, May 02, 2014

The CEO of global leading energy services company LR Senergy, James McCallum has issued a

stark warning that oil and gas productivity will drop if the drilling sector doesn’t unite and

take urgent action to tackle the drilling skills shortage and focus on excellence in well delivery

processes.

Speaking at the Industry Technology Facilitator’s (ITF) Bi-annual Members’ Forum meeting on Wednesday 23 April in Abu Dhabi, McCallum hosted a debate on drilling challenges and initiatives.

He highlighted that highly skilled engineers are needed now more than ever to execute drilling on complex, high risk projects such as Shah and Bab sour gas developments in the Middle East, but with

50% of petroleum engineers due to reach retirement age in the coming years, concerns are rising about the potential impact of a lost generation of talent.

McCallum said: “Concerns are rising that the exit of senior drilling talent will be accompanied by a drop in

productivity as new entrants are likelier to make costly errors, operate at a slower pace and extract lower

yields from more challenging deposits due to a lack of experience, resulting Incremental non-production

time (NPT) and inefficient operation.

“The set of skills required for drilling engineers in the region is changing, in particular on the type of high-

risk projects, where specific skills are required to identify any potential hazards. Risk judgement is very

important at a time when the drilling risks become significantly higher as geographically difficult and more

complex mature oil and gas fields are being exploited. Enhanced oil recovery rightly gets a great deal of

attention, however incremental oil recovery from efficient and effective drilling operations should be the

immediate priority.

“It is a serious issue which has been ongoing and while the drilling sector continuously talks of

collaborating, what we need to see is a commitment to this with urgent action.”

ITF’s meeting was attended by the organisation’s membership of international operating and service companies as well as technology specialists who were given a platform to showcase latest developments.




The drilling challenges debate heard the views of senior industry experts from NOCs, IOCs and major service companies. Initiatives to attract new talent to the industry, accelerating training programmes and launching drilling centres of excellence are among the actions being pursued by the industry to stem the challenge.

Dr Patrick O’Brien, CEO of ITF said: “Our forum also looked closely at the technical drilling challenges

faced by the industry, and our members gave us some good insight and direction on what technology

development we now need to facilitate on behalf our members and the wider industry. We had a number of

entrepreneurial drilling technology developers in the room that in time we believe can bring game changing

techniques to the industry. Casing while drilling is one such technology that would radically reduce drilling

downtime and improve drilling cost efficiencies that we all agreed was acutely needed at this time. My team

at ITF intend to pursue this agenda vigorously in the near term.”

The two day Bi-annual Members’ Forum was hosted by ADMA-OPCO and attended by more than 60 senior international oil and gas company representatives. ITF established a base in Abu Dhabi in 2012 and launched the Gulf Cooperation Council (GCC) cluster to help establish a vision for collaborative oil and gas technology research and development.

The agenda included updates from technology developers from ITF’s emerging project portfolio as well as interactive facilitated discussions on key themes including enhanced and increased oil recovery.

Founded in 2005, Senergy is an integrated energy services company that applies expertise and technology to assist the development and management of oil and gas fields and renewable energy projects. Our suite of core technical services centre on subsurface, well engineering and operations, site survey and geo-engineering, facilities development solutions and power engineering which are complemented by our software and training products.

Headquartered in Aberdeen, we have more than 650 employees and a further 100 associates, operating from offices in the UK, Norway, Middle East, Malaysia, Australia, USA and Indonesia.

As of 3 September 2013, Senergy is now a member of the Lloyd's Register Group (LR), the leading global provider of independent assurance and expert advice. The deal sees LR and Senergy provide a unique and comprehensive portfolio of services to the upstream sectors of exploration, production and transportation through to refinery and beyond




U.S. biomass-based diesel imports increase to record levels in 2013 Source eia.org : Sean Hill

The United States imports two varieties of biomass-based diesel fuel—biodiesel and renewable diesel. Last year, total U.S. imports of these two varieties of biomass-based diesel fuel reached 525 million gallons, compared to 61 million gallons in 2012. Two principal factors drove the increase in U.S. biodiesel imports: growth in domestic biodiesel demand to satisfy renewable fuels targets, and increased access to biodiesel from other countries. As a result, the United States switched from being a net exporter of biomass-based diesel in 2012 to a net importer in 2013 by a wide margin.

Growth in U.S. biomass-based diesel demand. The strongest driver of the resurgence in U.S. biomass-based diesel demand was the increasing Renewable Fuel Standard (RFS) target. Both biodiesel and renewable diesel qualify for the biomass-based diesel and advanced biofuel targets, as well as the overall RFS target. The total RFS target increased from 15.20 billion gallons in 2012 to 16.55 billion gallons in 2013. The biomass-based diesel and advanced biofuels targets increased from 1.00 billion gallons to 1.28 billion gallons, and from 2.00 billion gallons to 2.75 billion gallons, respectively. Biomass-based diesel fuels have higher energy content compared with ethanol, and thus generate more Renewable Identification Number (RIN) credits per gallon of fuel produced. In addition, renewable diesel meets the same American Society for Testing and Materials (ASTM) standards as petroleum diesel, and is thus not subject to the blending limits imposed on biodiesel.

What's the difference between biodiesel and renewable diesel?

Biodiesel refers to fatty acid methyl esters produced by a chemical reaction between vegetable oils or animal fats and alcohol (transesterification), and is most commonly blended with petroleum diesel in up to 5% by volume or 20% by volume (B5 and B20).




Renewable diesel refers to a diesel-like fuel that is compatible with existing infrastructure and in existing engines in any blending proportion. It is produced by refining vegetable oils or animal fats using a hydrotreating process.

Biomass-based diesel fuels also qualify for the California Low Carbon Fuel Standard (LCFS). The LCFS sets annual carbon intensity (CI) targets for fuel providers, to reduce the carbon content of gasoline and diesel fuels through 2020. Fuels with low CI values generate credits for fuel providers that can offset any deficits that they accumulate from fuels with higher CI values. Depending on the feedstock and the method of production, both biodiesel and renewable diesel have some of the lowest CI values among eligible fuels, and thus are valuable fuels for meeting LCFS targets.

Increased domestic biodiesel production only partially offset the effect that increased U.S. biodiesel consumption had on driving up imports. U.S. biodiesel production reached 1.34 billion gallons in 2013, a 35% increase over 2012, including a record 135 million gallons in December. This increase in production during 2013, especially the record levels near the end of the year, was driven in part by favorable blending economics by way of the $1.00 per gallon biodiesel blending tax credit, which expired on December 31, 2013. Given the elimination of the tax credit, soybean feedstock constraints, and limited renewable biodiesel production capacity, U.S. imports of biomass-based diesel fuels are likely to continue to play an important role in meeting the LCFS and the RFS targets going forward.

Increased access to biodiesel from other countries.

Last year's increase in imports of regular biodiesel were primarily from Argentina, particularly in the final four months (September to December). This likely resulted from a recent European Union antidumping duty imposed on biodiesel from Argentine producers in late 2013. The European Union was previously the destination for most of Argentina's biodiesel exports. The remaining volumes of regular biodiesel imports entered the United States on the East Coast (PADD 1) and Gulf Coast (PADD 3) from Indonesia and various European countries. U.S. renewable diesel imports reached 210 million gallons in 2013, eight times more than in 2012. Just over 77% of total U.S. renewable diesel imports came from Singapore and entered the United States on the West Coast (PADD 5), likely for California LCFS compliance.




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Your partner in Energy Services

Khaled Malallah Al Awadi, MSc. & BSc. Mechanical Engineering (HON), USA ASME member since 1995 Emarat member since 1990

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Khaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 yearsKhaled Al Awadi is a UAE National with a total of 24 years of experience in theof experience in theof experience in theof experience in the Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as

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Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developed as compressor stations . Through the years , he has developed as compressor stations . Through the years , he has developed as compressor stations . Through the years , he has developed

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routes. Many years were spent drafting, & compiling gas routes. Many years were spent drafting, & compiling gas routes. Many years were spent drafting, & compiling gas routes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs for transportation , operation & maintenance agreements along with many MOUs for transportation , operation & maintenance agreements along with many MOUs for transportation , operation & maintenance agreements along with many MOUs for

the local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcasted Energy program broadcasted Energy program broadcasted Energy program broadcasted

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