New base special 22 may 2014

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NewBase 22 May 2014 Khaled Al Awadi

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Maersk Oil cuts academy, industry gap with Qatar development programme …. http://www.gulf-times.com/

A group of Qatari employees at the country’s largest oil producer, Maersk Oil have completed the latest stage of a novel programme that aims to develop ‘the leaders of tomorrow’.

Maersk Oil’s Qatari Development Programme is open to employees early in their careers and bridges the gap between the academic environment of university and the skills needed to develop outstanding workplace performance.

Maersk Oil began the two-year development programme in November last year, as part of its “Revitalised Qatarisation Strategy”, which includes a commitment to quadruple the number of Qataris in leadership and senior specialist positions by 2017.

Maersk Oil Qatar deputy managing director Sheikh Faisal bin Fahad al-Thani said, “Qatarisation is a core business priority for Maersk Oil. We have made great strides in the past five years by doubling the number of Qatari employees and increasing those with a bachelor’s degree, but we are committed to attracting, developing and retaining even more Qatari leaders in the future. Schemes like the Qatari Development Programme will help us do just that.”

The Qatari Development Programme includes a mixture of formal modules, and what are known as action learning sets, where smaller groups meet to discuss workplace issues, typically around prioritisation, problem solving and managing workloads.

Qatari engineer at Maersk Oil Qatar’s offshore facility.




One of the programme’s participants, process engineer Aisha Ahmad al-Nuaimi, has welcomed the development of so-called softer skills.

She said: “As an engineer, this is something different - it gives us skills to develop the other side of our personality, leadership skills, and communication with our colleagues. While companies usually focus on technical training, the Qatari Development Programme is unique, and it shows how Maersk Oil Qatar is keen to develop employees.”

Joanna Rawbone, director, Scintillo – a specialist UK-based learning development company – is assisting Maersk Oil with the Qatari Development Programme.

She said, “The action learning sets encourage the fourteen participants to be more resourceful when it comes to problem solving, so instead of always looking to their manager, they can work through issues by themselves or with colleagues. This benefits them in their development as possible future leaders and also it ensures that Maersk Oil gains a skilled, enthusiastic and more diverse band of potential leaders who can propel the business forward.”

The Qatari Development Programme is rooted in an exhaustive 12-month study, which included a survey of employees and detailed mapping and analysis of best practice in Qatar and abroad.

Maersk Oil Qatar head (Qatarisation) Sheikh Jassim al-Thani said, “The two-year Qatari Development Programme is a large investment by Maersk Oil in young Qataris, but it is clearly paying off. The programme is a key pillar of our Qatarisation strategy; we found that the first two years of employment was a critical period to develop Qatari employees and set career paths. Ultimately, we want to provide faster, more-structured career development.”

Another Qatari participant, Hussam al-Qatouni said: “As an engineer, I think this programme will help my development, as it takes me from the technical side to the day-to-day aspect. If anyone thinks that their degree without skills in other areas will guarantee their development, I think this is wrong. We need to gain skills on how to manage our time, internal communications with our colleagues and managers, as well as other important areas.”

ABOUT MAERSK OIL QATAR

Maersk Oil entered into an Exploration and Production Sharing Agreement (EPSA) with Qatar

Petroleum (QP) in 1992. The EPSA included an oil-bearing reservoir – the Al Shaheen field –

which had been deemed uneconomic by others as its reservoirs were extremely thin and

stretched across vast distances. Despite these difficulties, Maersk Oil produced first oil just two

years later and is now producing over one third of Qatar’s daily oil production, some 300,000




China, Russia sign $400bn gas supply deal Reuters

China and Russia signed a long-awaited, $400bn gas supply deal yesterday, securing the world’s top energy user a major new source of cleaner fuel and opening a new market for Moscow as Europeans look elsewhere for their energy.

Russian President Vladimir Putin and Chinese counterpart Xi Jinping applauded as they witnessed the deal being signed in Shanghai between state-controlled entities Gazprom and China National Petroleum Corp (CNPC).

The deal is a political triumph for Putin, who is courting new partners in Asia as customers in Europe attempt to reduce their reliance on Russian gas to bolster their bargaining positions with Moscow after its seizure of Crimea from Ukraine. But from a

commercial point of view, much depends on the so far undisclosed price and other terms of the contract, which has been more than a decade in the making. Industry insiders said China had the upper hand in negotiations as they entered their final phase, aware of Putin’s need for new customers as his isolation in Europe intensified.

“This is indeed a historic event for the gas sector of Russia and of the Soviet Union,” he said. “This is the biggest contract in the history of the gas sector of the former USSR. “I want to stress that there was hard work done on the expert level. Our Chinese friends are difficult, hard

negotiators,” he said, noting that negotiations went on until 4am.

“Through mutual compromise we managed to reach not only acceptable, but rather satisfactory, terms on this contract for both sides. Both sides were in the end pleased by the compromise reached on price and other terms.” Industry estimates showed that the price of the agreement may have come in at around $350 per thousand cubic metres. The Western

Gazprom CEO Alexei Miller (centre), President of

China National Petroleum Corporation (CNPC) and

Chairman and President of PetroChina Zhou Jiping

(right) exchange documents as Russian President

Vladimir Putin looks on during a signing ceremony in

Shanghai yesterday.




European average is $380.Company sources said China offered to pay more than the approximately $9 per million British thermal units (mmBtu) it pays for Turkmenistan supplies, while the lowest offer by Russia was at about $9.67 per mmBtu. Another potential sticking point has been whether China would pay a lump sum up front in order to fund considerable infrastructure costs.

Gazprom CEO Alexei Miller said that element of talks remained unresolved, but Putin said China would provide $20 billion for gas development and infrastructure and that the price formula was similar to the European price tied to the market value of oil and oil products. Analysts said broader, political factors were likely to have been at play around the negotiating table.

“Given the EU sanctions that could potentially hit Russia, I don’t think Gazprom is in a position to strike a very high price for its gas,” said Gordon Kwan, head of Asian oil research at Nomura. He added that CNPC would be driving a hard bargain in the wake of a corruption investigation that rocked the company last year and as Xi seeks to stamp out graft more broadly. The gas will be transported along a new pipeline linking Siberian gas fields to China’s main consumption centres near its coast. Russia will begin delivering from 2018, building up to the annual target of 38 billion cubic metres, officials said.

Putin announced that Russia planned to invest $55bn in exploration and pipeline construction up to China. CNPC said it would build the Chinese section of the pipeline.




Tanzania receives five bids for oil and gas blocks Source: Reuters

Tanzania, a hotspot for natural gas exploration, has received five bids for just half of the eight oil and gas blocks it offered in its latest bidding round, its upstream regulator said on Wednesday. Tanzania, which has made big discoveries of natural gas off its southern coast, had offered seven deep-sea offshore blocks and one block in Lake Tanganyika. China's top offshore oil producer, CNOOC Ltd, and Russia's state-run

Gazprom were among companies that submitted bids for the blocks on offer in the fourth round. Statoil and ExxonMobil, which have made big gas discoveries off Tanzania, have submitted a joint bid for one of the offshore blocks.

'The evaluation process will start immediately and we will announce winners of the bids as soon as possible within the timeframe of the fourth licensing round,' Yona Killagane, managing director of the state-run Tanzania Petroleum Development Corporation (TPDC), told Reuters. Killagane did not say when the winners will be announced. The licensing round closed on May 15.




CNOOC, a newcomer in Tanzania's rapidly-expanding oil and gas industry, will battle with Statoil and

ExxonMobil for offshore Block 4/3A, which covers 2,620.3 sq kms. Gazprom has applied for Block 4/3B offshore Tanzania, covering an area of 3,045 sq kms. Abu Dhabi state-owned investment fund Mubadala

has applied for offshore Block 4/2A, which covers an area of 3,630 sq kms, while another UAE firm, Ras Al

Khaimah Gas, has submitted a bid for the Lake Tanganyika North block, with a size of 9,670.2 sq kms.

Four offshore blocks, 4/3B, 4/4A, 4/4B and 4/5B, did not attract any bids, TPDC said. Britain's BG Group and Ophir Energy, which have been at the forefront of exploration in Tanzania, did not submit any bids for the blocks on offer. The deep sea offshore blocks are located in water depths of 2,000 to 3,000 metres adjacent to proven prospective blocks, while the Lake Tanganyika North block is in a water depth of 1,500-metres along the east African rift system, the government said in its bidding round announcement.

Tanzania has so far signed 25 production sharing agreements (PSAs) with some 17 international energy companies, including BG Group, Statoil, Brazil's Petrobras, Royal Dutch Shell, Exxon Mobil and Mubadala Petroleum. Winners of the latest bidding round would be subjected to new PSA terms that experts said toughen some of the conditions for energy firms seeking to explore and develop the east African nation's big gas prospects.

Tanzania has 46.5 trillion cubic feet (tcf) of proven natural gas reserves, up from 42.7 tcf previously, and expects exploration off its southern coast will result in more finds. See TPDC announcement: Closing of the 4th Tanzania Deep Offshore and North Lake Tanganyika Licensing Round




Repsol facing problems with Welwitschia drilling (Namibia) Source: Repsol

Spanish oil giant Repsol is experiencing difficulties with its drilling operation offshore Namibia. According to Tower Resources, a company which owns a share in the Namibia PEL0010 block in which Repsol is the operator, following the spud of Welwitschia-1 on May 1, and installation of the 36-inch casing it was observed that the wellhead housing had “slumped”.

A decision was taken by the JV Partners to plug and abandon the Welwitschia-1 well and re-spud the well as Welwitschia-1A at a distance of approximately 50 metres from the original spud location. Welwitschia-1A was spud at 3:30am on 1 May 2014 with no recurrence of the above issue. Despite the delay, it was expected that the re-spud would not impact on the overall cost or timing of the well.

Repsol has since reported a further operational delay to the drilling programme due to a fault with part of the Blow Out

Preventer (“BOP”) control system. Drilling has been suspended whilst Repsol and the drilling contractor, Rowan, are taking measures to rectify the fault so that they are able to recommence drilling safely. It is estimated that commissioning issues relating to the BOP control system will delay further drilling until the end of May 2014.

The current status of the well is that the casing has been set to a depth of 1,879 metres and Tower expects drilling into the primary target section shortly following the restart of drilling operations.

The cost implications of the delay are currently being examined by the JV Partners and depend upon allocation between Repsol and the drilling contractor, Rowan.

However, Tower says it is the view of Tower and the JV Partners that the well will be completed within budget despite the recent delays.

Jeremy Asher, Tower Resources’ Chairman, said: “It is not unusual to encounter technical

issues with new equipment and in particular

BOPs on-board a new drill-ship such as the

Rowan Renaissance. However, safety is of

paramount importance to Tower and its JV

Partners and we are confident that Repsol

and Rowan will resolve the BOP issues

shortly and we look forward to informing the market when drilling recommences. These issues have no

connection with the prospects for the well itself, which remain as exciting as ever”.




Shell to build world-largest FPSO for Nigeria Bonga South West

Royal Dutch Shell (Shell) and its partnering major companies, ExxonMobil from USA, Total from France and Eni from Italy, are entering the bidding phase on the Bonga South West floating, production, storage and offloading (FPSO) vessel to be moored in the Block 118 offshore Nigeria.

Covering the Blocks 118 (previously called 212), 132 and 140 in the Gulf of Guinea, Bonga oil and gas field ranks among the largest fields on the West Coast Africa requiring an exploration and development in phases.

Located approximately 135 kilometers west of Port Harcourt in Nigeria, Bonga was discovered by 1,300 meters water depth in 1995 and started the first production in 2005 with a first FPSO.

In 2001, Shell and its partners discovered Bonga South West (Bonga SW) large enough to trigger a stand alone exploration – production project with an additional FPSO.

In 2004, a third field was discovered in the Block 140 branded as Bonga North or Aparo 95% owned by Chevron.

The Aparo field appeared in fact to belong to the same geological structure as Bonga South West.

Therefore Chevron had easy to join Bonga South West partners for a unitized development.

In Bonga South West Shell and its partners share the working interests in such way as:

- Shell 55% is the operator - ExxonMobil 20%

- Eni‘s subsidiary Nigeria Agip Oil Corporation (NAOC) 12.5% - Total 12.5%

Estimated to hold 820 million barrels of oil, Shell Bonga South West may require one of the largest FPSO ever built with topsides to weight 35,000 to 40,000 tonnes.

Shell Bonga South West FPSO critical on local content




According to the conclusions of the front end engineering and design (FEED), Shell Bonga South West FPSO should have capacities of:

- 225,000 barrels per day (b/d) for oil processing

- 270 million cubic feet per day (cf/d) natural gas processing

- 2.5 million barrels of oil storage

- 400,000 b/d of water injection

In addition the subsea production and export system should include:

- 22 production wells

- 22 water injection wells

- 85 kilometers pipe-in system

- 65 kilometers umbilicals

- 98 kilometers gas export pipeline

Shell and its partners will call for tender the engineering, procurement and construction (EPC) contracts for the FPSO and the subsea production and export system separately.

Regarding the FPSO, the Nigeria government is requiring to increase the local content compared with previous projects such as Egina.

This local content constraint combined with Shell technical specifications and the financial targets of the project has a big impact on the qualification of the engineering companies and shipyards for Bonga South West.

In this complex ruling context, Shell and its partners will evaluate first the technical offers in including the local content proposals to perform a first selection, then they will consider the commercial offers from the remaining bidders only.

Considering that one of the bidder is already building shipyard in Nigeria supported by a comprehensive training program for the welders and other workers, it may take a solid market leadership in view of Shell Bonga South West.

Based on this scenario, Shell and its partners ExxonMobil, Eni and Total, are expecting to make the final investment decision (FID) on the Bonga South West FPSO by the end of 2014 with the first shipment to be loaded by 2020.




Petronas Says Canada Gas Stocks Halfway to Goal for LNG Investment by Reuters

Malaysia's Petronas has proven up about half of the 15 trillion cubic feet (tcf) target for Canadian gas reserves it needs to make a final investment decision on its $32.9 billion (C$36 billion) natural gas export project, Chief Executive Shamsul Azhar Abbas said on Wednesday.

The state-owned oil company plans to drill aggressively through the summer to further prove out its reserves in Western Canada ahead of a final go or no-go decision, anticipated by year-end, on a gas field, pipeline and liquefied natural gas (LNG) export terminal development.

"To date, I am pleased to report that we have already proven approximately 50 percent of our 15 tcf target to reach final investment decision," Shamsul said at an industry conference in Vancouver. He added that the company plans to have 25 to 30 rigs running throughout the summer on its gas fields in northern British Columbia and Alberta.

Petronas dove into the Canadian natural gas space in 2012 with its C$5.2 billion takeover of Progress Energy Resources and is now racing to develop its Pacific NorthWest LNG project near Prince Rupert in northern British Columbia. The project is just one of about a dozen LNG export terminals proposed for the province's rugged Pacific coast, as energy companies from around the world scramble to build the facilities to export cheap Canadian gas to Asian markets.

Petronas has vaulted ahead of its rivals, aiming to start construction on the massive development next year, with first shipments in 2019. "The window to approve, build and deliver the first cargo is short and very tight considering the competition out there,"

Shamsul said. In addition to ensuring there are adequate reserves to meet plans to export some 12 million tonnes of LNG per year, the company is still looking for clarity from British Columbia on its proposed two-tier LNG tax. The province, which is banking on an LNG boom to boost government revenue and create jobs, committed earlier this month to provide certainty to Petronas on all government-related costs by the end of November.

Shamsul warned that project economics remain a key concern for investors and said governments must introduce frameworks to enhance a project's economic viability, such as tax breaks or incentives, rather than policies that inhibit investment.

"Let's not slaughter the goose before it has a chance to hatch the golden egg," he said. "This is a once in a lifetime opportunity for B.C., we must be careful to not squander it away by banking on unrealistic expectations and misconceived perceptions."




Indonesia: Pertamina steps up bid for control of the biggest gas field Source: Reuters

Indonesian national oil and gas firm Pertamina said it is pushing the government to gain control of the country's top gas producing field that is currently operated by Total of France whose contract is due to expire in 2017.

Indonesia only allows oil or gas firms to extend their contracts once for up to 20 years, and gives Pertamina the right to take over expiring contracts if it wants them. Total has warned that output from the Mahakam

field in East Kalimantan, currently at around 1.66 billion cubic feet per day, could drop sharply if it is not allowed to extend its current contract beyond 2017. Total has promised to invest up to $7.3 billion before then if the contract is renewed, but energy resources are highly politicized in Indonesia and with elections approaching in July no decision has been made.

Pertamina, which plans to increase output nearly five-fold by 2025, has written letters reminding the government it is ready to take over the Mahakam field. 'We reaffirmed we are ready to operate it,' Pertamina upstream director Muhammad Husen told Reuters on the sidelines of the annual Indonesia Petroleum Association (IPA) conference in Jakarta, adding that his firm had sent three letters so far. 'Maybe the government needs time to consider it.'

Husen declined to comment on the exact contents of the letters or on how much Pertamina would spend on the field. Total said it was aware of the letters, but was still waiting for a response from the government to its latest proposal on the Mahakam field that it submitted in July, 2013.

IPA president Lukman Mahfoedz urged the government to produce a 'clear and transparent' regulation on contract extensions that takes into account the roles of Pertamina, international oil companies and




Indonesian oil and gas firms. 'We are waiting,' Mahfoedz said, referring to the high risks and lack of legal certainty energy investors face in Indonesia. Over the next five years around 20 of Indonesia's production-sharing contracts will expire, he said, accounting for around 635,000 barrels of oil equivalent per day (boepd) in 2013, or 30 percent of Indonesia's total oil and gas output that year.

The government is preparing regulation that would simplify its processing of expiring oil and gas contracts, Energy and Mineral Resources Minister Jero Wacik told reporters. 'In this era of democracy when they want to extend one contract the noise they make is extreme,' Wacik said. 'Previously there wasn't very clear regulation,' he said, adding that the new rules would eliminate lengthy case-by-case negotiations. However, Wacik did not say when the new regulation would be ready.

Of the 20 contracts that are due to expire, around 10 have requested extensions 'and we are processing these', the chief of Indonesia's oil and gas regulator (SKKMigas), Johannes Widjonarko, told reporters adding that some would be handed to Pertamina. Eni will likely be given a permit to continue exploring a block it took over from Hess Corp in Indonesia's East Timor, beyond a four-year limit, SKKMigas commercial director Widhyawan Prawiraatmadja told reporters. 'I think a company like Eni doesn't have problem with their commitments, so most likely we will give them more time for exploration,' Prawiraatmadja said.

In 2014 Indonesia budgeted oil and gas output to reach more than 2.1 million boepd, although this figure is expected to be revised down because of delays in developing ExxonMobil's Cepu block in East Java.

Pertamina now faces the combined challenges of stemming oil production declines and meeting domestic demand. Much of the reserves remaining under Pertamina's control require EOR techniques, currently beyond the technological capacity of domestic firms, or the development of basic infrastructure in remote areas of the country (mainly in the east). Partly because of an uncertain regulatory atmosphere and government measures to support local companies, foreign investment in extracting these reserves remains limited. In addition, Indonesia's domestic operations have been limited by disputes with IOCs operating within Indonesia.




Schlumberger unveils reservoir mapping service Source : Schlumberger

Leading oilfield services company Schlumberger has launched the GeoSphere reservoir mapping-while-drilling service.

The new technology reveals features in subsurface beddings and fluid contacts at the reservoir scale to optimise well landing operations, steering capabilities and mapping of multiple boundaries using new deep-directional resistivity measurements enabled by proprietary real-time interpretation techniques, said a statement. Steve Kaufmann, Drilling and Measurements, said: “With GeoSphere technology, Schlumberger is introducing the first-ever reservoir mapping-while-drilling service that enables customers to map their reservoirs using unprecedented depth of investigation measurements around the wellbore combined with a novel mathematical inversion methodology.” “This long-awaited technology milestone commercialisation now enables asset teams to seamlessly integrate the data provided by the reservoir mapping-while-drilling service with other downhole measurements to optimise production and reservoir management.” With a deep range of investigation that extends more than 100 ft from the wellbore, drilling teams can use the GeoSphere service to reduce drilling risk and accurately land wells, resulting in the elimination of pilot holes, said the statement. In addition, the real-time reservoir mapping-while-drilling service enables the positioning of wells within target reservoirs, away from fluid boundaries, leading to increased reservoir exposure as well as allowing geoscientists to refine their seismic interpretation and geological and structural models. The GeoSphere service has been tested in more than 140 wells worldwide, including locations in North America, South America, Europe, Middle East, Russia and Australia, it added. -

Reveal subsurface beddings and fluids contacts critical for landing, steering, and refining field development plans.

Reservoir-scale map created by GeoSphere




Italy: ADX Energy awarded permit offshore Italy Source: ADX Energy

ADX Energy has announced that the Italian Ministry of Industry has awarded the offshore exploration permit d 363 C.R-.AX to ADX. The awarded permit is on trend with ADX’s offshore Tunisian Kerkouane

Permit and adjacent to its previously awarded d 364 C.R-AX license. ADX is the operator of the permit and holds a 100% interest via its fully owned Italian subsidiary.

The block is on the same structural trend as the proven onshore Cap Bon oil & gas fields in Tunisia, the large sized ADX 3D covered Dougga West and Elissa oil prospects in the Kerkouane block and contains – on trend – the Nilde oil field inside the Italian license now awarded to ADX.

In addition to its excellent prospectivity the area would also allow relatively smaller discoveries to be commercially developed. This is due to a combination of water depths predominantly less than 100 meters and the excellent fiscal regime in Italy.




U.S. consumers’ energy spending rose this winter Eia.gov

U.S. consumer energy expenditures this past winter (fourth quarter of 2013 and first quarter of 2014) were $14.0 billion (4.4%) higher than the previous winter, as cold weather east of the Rocky Mountains led consumers to pay more to heat their homes but less to fuel their cars. Energy expenditures as a share of disposable income increased 0.1% from the winter of 2012-13 to last winter, with most of the growth occurring in the first quarter of 2014.

Transportation fuels account for the largest contribution to consumer energy expenditures, followed by electricity, natural gas, and heating oil and propane. Energy expenditures vary by season and with market conditions, and are a function of the prices and consumption of each type of energy.

• Transportation fuel expenses declined $5.8 billion (-3%) last winter compared with the previous winter, as prolonged bad weather reduced driving and gasoline consumption. The transportation fuel share, which can represent more than two-thirds of energy expenditures during the summer when motorists drive the most, declined from 58% in the winter of 2012-13 to 54% last winter.

• Electricity expenditures increased $7.9 billion (10%) last winter compared with the previous winter. Electricity expenditures include expenses for utilities and are highest during the summer months when air conditioning boosts electricity demand. Nearly two-thirds of the homes that use electricity as their main heating fuel are concentrated in the South, which has lower heating demand than other parts of the nation.

• Natural gas expenditures increased by $5.8 billion (16%) last winter compared with the previous winter. Natural gas expenditures, which typically peak in the first quarter of each year because of heating demand, also include the cost of using other natural gas appliances such as water heaters and clothes dryers.




• Heating oil and propane expenditures together were $6.0 billion (27%) higher than the previous winter. Heating oil and propane make the smallest contribution to aggregate energy expenditures because they are used predominantly for space heating and are used to heat a relatively small number of homes across the country. However, their use is concentrated in areas of the country that were hit the hardest with cold weather this past winter.

Source: U.S. Energy Information Administration, based on U.S. Bureau of Economic Analysis




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

Energy Services & Consultants Mobile : +97150-4822502

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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

Technical Affairs Specialist for Emirates GeTechnical Affairs Specialist for Emirates GeTechnical Affairs Specialist for Emirates GeTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for neral Petroleum Corp. “Emarat“ with external voluntary Energy consultation for neral Petroleum Corp. “Emarat“ with external voluntary Energy consultation for neral Petroleum Corp. “Emarat“ with external voluntary Energy consultation for

the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations the GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operations

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NewBase 22 May 2014 K. Al Awadi

Economy & Finance

New base special 22 may 2014