New base 977 special 19 december 2016 energy news

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NewBase 19 December 2016 - Issue No. 977 Senior Editor Eng. Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE

UAE: ADCO offer BP 10% of Abu Dhabi’s onshore oilfields for US$2.2bn

The National - Anthony McAuley

BP has taken a 10 per cent stake in Abu Dhabi’s main onshore oilfield concession after a prolonged negotiation, agreeing to pay about US$2.2 billion for the stake through the issue of new shares.

As part of the deal, BP will become the manager of the Bab oilfield, one of the six main oilfields in the Abu Dhabi Company for Onshore Oil Operations (Adco) concession.

In an unusual move, BP has agreed to pay for its stake through the issue of new ordinary shares representing about 2 per cent of its issued share capital, to be held on behalf of the Abu Dhabi Government.

Sultan Al Jaber, the chief executive of Abu Dhabi National Oil Company (Adnoc) and Minister of State, said: "This agreement marks a milestone in our efforts to forge new partnership models that

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bring technology, expertise and financing aimed at maximising the value of our resources and supporting the transfer of knowledge."

BP was one of the shareholders in the original Adco concession that expired two years ago, but had baulked at the high price tag set on the new 40-year concession when France’s Total agreed at the start of last year to pay about $2.2bn for its 10 per cent stake.

"BP will work closely with Adnoc to realise the full potential of these world-class resources, and I welcome Abu Dhabi as an important investor in BP," said Bob Dudley, the oil major’s chief executive, who was in Abu Dhabi to sign the deal with Mr Al Jaber.

"This agreement will provide BP with long-term access to significant and competitive resources that we already understand very well," Mr Dudley said. "We will bring our people, cutting-edge technology and experience of managing mature giant fields around the world to help maximise recovery from these assets."

One of the key considerations for Abu Dhabi’s Supreme Petroleum Council, which ultimately decides on the concession holders, was the pitches that potential Adco stakeholders made about how they would use their technologies and experience to enhance the oil recovery rates for the Adco oilfields.

Typically, oilfield recovery rates have been at about 40 per cent of their estimated reserves, but Abu Dhabi leaders have wanted to push that substantially higher, to rates of as much as 70 per cent, which would represent billions of dollars of extra revenue over the lives of the fields.

But the immediate sticking point for shareholders had been the price tag of the Adco shareholding, especially in the lower oil price environment of the past two years, as well as the relatively low payment terms per barrel for the concession holders.

Inpex of Japan and GS Energy of South Korea (with the financial backing of the Korea National Oil Corporation), have also taken stakes of 5 per cent and 3 per cent, respectively. Neither will be field operators, although Japan and South Korea are Abu Dhabi’s two largest and longest-standing customers for crude oil exports.

Adnoc holds 60 per cent of Adco and said in a statement that it continues to negotiate with other potential stakeholders for the remaining 12 per cent on offer.

BP will take over operatorship of Bab from Total, which had stepped in on an interim basis to move along the field’s development, according to the Total chief executive, Patrick Pouyanne.

As part of its concession deal, Total operates the South East and Bu Hasa oilfields, which together cover about two-thirds of Adco’s output, which is currently at a rate of about 1.66 million barrels per day (bpd), or slightly more than half of Abu Dhabi’s 3.1 million bpd output.




Neither BP nor Adnoc would disclose the specific compensation terms of the deal, but BP’s chief financial officer, Brian Gilvary, said via a statement: "We have worked closely with Adnoc to structure an agreement that is attractive and strategic for both parties … the lower cost characteristics of this already producing conventional onshore oil development will be accretive to earnings and cash flow, while providing BP with another building block of long-term growth."

Industry estimates have put the compensation at less than $2 per barrel for the concession stakeholders, but statements by Total executives and others suggest that there are incentives built into the deal for exceeded targets on the oilfield developments, plus the potential to increase terms by trading the crude oil they receive.

BP said that it will be sending about 50 of its staff to work at Bab.

BP also holds a 14.67 per cent interest in Adma-Opco, one of Abu Dhabi’s two main offshore concessions, plus 10 per cent of both the Abu Dhabi Gas Liquefaction Company (Adgas) and the National Gas Shipping Company (Ngsco).

BP said its net share of oil and gas production from Abu Dhabi is expected to rise from about 95,000 bpd to approximately 260,000 bpd next year, compared with the company’s total daily output last year of about 2 million bpd.

The deal is also expected to boost diversification efforts of Abu Dhabi government as it will have 2 per cent share in BP which would enable the emirate to generate extra cash, according to Dr Mamdouh G Salameh, an oil economist based in London.

“The agreement between Adnoc and BP marks a milestone in Adnoc’s efforts to forge a new partnership model that brings technology, expertise and financing aimed at maximising its resources,” he said adding that the deal could enable Abu Dhabi to raise the recovery factor from its oil wells.




Saudi Aramco moves ahead with wind and gas projects to cut domestic oil use.. The National

Saudi Arabia’s state oil company, Saudi Aramco, announced a major new gas plant contract and took delivery of the kingdom’s first wind turbine this week, as it moved ahead with plan to cut domestic oil consumption for power generation.

Aramco said on Sunday it had taken delivery of a GE 2.75-120 wind turbine, which will be used as a demonstration installation to displace diesel at its power plant at Turaif, in the far north near its border with Jordan, where conditions are best for testing.

The two projects highlight Saudi Arabia’s commitment to renewable energy while emphasising that natural gas is the main driver of its energy diversification plans.

"The intention for renewables is there but like the rest of the Gulf, it is making a really aggressive push towards getting more gas," said Steve Griffiths, the vice president for research at the Masdar Institute of Science and Technology in Abu Dhabi.

The Saudi economic road map, Vision 2030, this year set a goal of 9.5GW for all renewables by 2023, with solar to provide 3.45GW. That compared with the old King Abdullah City for Atomic and Renewable Energy plan, which foresaw 41GW of generating capacity for solar alone by 2032, with more than half to be up and running by 2020.

Saudi Arabia also scaled back its target for the share of renewables in its energy mix, from 50 to 10 per cent, while sharply raising its target for natural gas’s share to 70 from 50 per cent.

Huntak Kim, Doosan EPC division’s chief executive, said: "The cogeneration plant will enhance the overall energy efficiency of the Fadhili gas plant (and) will give Doosan an increased advantage to deliver more of its advanced power solutions and services where 40,000MW of power capacity increase from combined heat and power plants is planned by 2024."

GE said it expects to start generating electricity from its giant turbine – with a wing span of 120 metres, or 50 per cent wider than an Airbus 380 – next month. The output will be modest – displacing about 18,600 barrels of diesel a year – but the turbine has digital equipment that will allow GE and Aramco to analyse wind conditions and turbine efficiency.

"It highlights that wind energy generation in the kingdom is real and heralds a new era of renewable energy that clearly shows to the world that action is being taken to support the renewable goals of Vision 2030," said Hisham Albahkali, GE’s Saudi Arabia country head.

Despite the world glut in natural gas, which has depressed prices and pushed up demand from Gulf countries, "the Saudi commitment to renewables seems pretty much still in tact," said Mr Griffiths. "But the projects need to start evolving a little quicker" to meet targets.




Libyan Crude Output Return shakes oil market Bloomberg - Jessica Summers

Oil hovered near $52 a barrel as investors eyed the potential return of crude volumes from Libya and await output cuts in January as part of an OPEC and non-OPEC deal.

Futures were little changed in New York after swinging between gains and losses. Libyan oil-facility guards backtracked on an agreement to allow supply to flow from the El Feel and Sharara fields, two of the country’s biggest fields. Investors await production cuts by OPEC and non-OPEC producers starting early next year.

Oil has traded near $50 a barrel since the Organization of Petroleum Exporting Countries agreed Nov. 30 to reduce production for the first time in eight years. Many non-OPEC producers, such as Russia, agreed to join the deal as well. Goldman Sachs Group Inc. last week increased its second-quarter crude-price forecasts and predicted stockpiles would return to normal by mid-2017 amid the curbs.

There are little fundamental drivers until the market can evaluate OPEC, non-OPEC production cuts in January, according to Mike Dragosits, senior commodity strategist at TD Securities in Toronto. “We’re in a pretty quiet period now. What you’re seeing is a reaction to the U.S. dollar flows,” he said by telephone.

WTI for January delivery, which expires Tuesday, fell 5 cents to $51.85 a barrel at 9:58 a.m. on the New York Mercantile Exchange. Total volume traded Monday was about 20 percent below the 100-day average. The more-active February future was down 7 cents to $52.88.




Brent for February settlement dropped 15 cents, or 0.3 percent, to $55.06 a barrel on the London-based ICE Futures Europe exchange. The global benchmark crude traded at a premium of $2.18 to WTI for the same month.

The Bloomberg Dollar Spot Index, a gauge of the greenback against 10 major peers, was little changed, after falling as much as 0.3 percent earlier.

Libyan Output

A group of Libyan guards prevented the flow of oil by pipeline, Khaled Hadloul, an engineer at Mellitah Oil & Gas, which operates El Feel, said by phone. The Repsol SA-operated Sharara field is also yet to restart because both fields feed into the same pipeline network, Hadloul said.

“We’re watching what’s going on in Libya. That’s pushing around the market, too,” John Kilduff, a partner at Again Capital LLC, a New York-based hedge fund that focuses on energy, said by telephone.

Libya’s ‘Elephant,’ Sharara Oil Fields Restart Said Halted

Libyan oil-facility guards prevented two of the country’s biggest fields from resuming production, days after the National Oil Corp. reached an agreement to restart operations there to boost output in the politically divided OPEC state.

The El Feel, or Elephant, and Sharara fields still aren’t operational after they were shut more than a year and a half ago, an NOC official said Sunday by phone, asking not to be identified for lack of authorization to speak to news media. A group of guards backtracked on their agreement to let oil flow by pipeline from both fields, Khaled Hadloul, an engineer at Mellitah Oil & Gas, which operates Elephant, said by phone.

“It’s not clear when the actual output will start,” Hadloul said. “Negotiations with the guards are ongoing,” and the reasons why the guards reversed their position are unclear, he said. Hadloul said he knew that Repsol SA-operated Sharara, Libya’s largest field, also has yet to restart because both fields in western Libya feed into the same pipeline network. Eni SpA has a stake in Elephant.




Mauritania and Senegal:BP agrees deal with Kosmos Energy to partner on world-class discoveries ..Source BP

The deal gives BP a leadership position in an emerging world-class, low-cost gas basin with advantaged access to global gas markets

BP has signed agreements with Kosmos Energy to acquire a 62% working interest, including operatorship, of Kosmos’ exploration blocks in Mauritania and a 32.49% effective working interest in Kosmos’ Senegal exploration blocks -- acreage which holds world-class deepwater gas discoveries and exploration prospectivity across both countries.

The approx. 33,000 sq kms of acreage covered by today’s agreements includes the Tortue field, estimated by Kosmos to contain more than 15 tcf of discovered gas resources. The total acreage,




by Kosmos’ estimates, could contain roughly 50tcf of gas resource potential and in excess of 1 billion barrels of liquids resource potential.

BP will invest nearly one billion dollars mostly in the form of a multi-year exploration and development carry to acquire a 62% interest and operatorship of offshore Blocks C-6, C-8, C-12 and C-13 in Mauritania and an effective 32.49% interest in the Saint-Louis Profond and Cayar Profond blocks in Senegal.

BP chief executive officer Bob Dudley commented:

'BP’s entry into Mauritania and Senegal represents an exciting strategic opportunity to work with Kosmos Energy in an emerging world-class hydrocarbon basin. We believe our expertise in integrating the gas value chain, together with a talented exploration partner in Kosmos, along with the support of the Mauritanian and Senegalese governments brings together all the elements needed to create a new LNG hub in Africa.'

In order to reduce development time and drive capital efficiency, the partners plan to process and transport the gas from Tortue at a nearshore LNG facility. The proposed complex could be expanded in phases to accommodate future gas discoveries.

Under the terms of the agreements, BP and Kosmos have also agreed that Kosmos will remain the technical operator for the

exploration phase of the project and drill three new exploration wells beginning in 2017.

In addition to the existing blocks, the companies have agreed to cooperate in areas of mutual interest in offshore Mauritania, Senegal and The Gambia with Kosmos acting as the exploration operator and BP as the development operator.

Subject to government approvals, the agreements are expected to close by the first quarter of 2017.

Background

Under the terms of the agreements, BP will pay Kosmos a cash bonus of $162 million on completion. Moving forward, BP will carry Kosmos’ exploration and appraisal costs of $221 million along with Kosmos’ development costs of $533 million, including front-end engineering and design studies. Project sanction is expected by 2018.

Kosmos will also receive a contingent bonus of up to $2 per barrel for up to 1 billion barrels of liquids, as a production royalty, subject to a future liquids discovery and oil price.

BP’s proposed share of the Contractor Group results in a working interest in Mauritania consisting of Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier 10%, BP 62% and Kosmos 28% and an effective working interest in Senegal consisting of Société des Pétroles du Sénégal 10%, BP 32.49%, Kosmos 32.51% and Timis Corporation 25%.




UK:First Gas at Cygnus, UK's Largest Producing Gas Field in 2017 by Andreas Exarheas|Rigzone First gas has flowed from the Cygnus field, which is on course to be the largest producing gas field in the UK North Sea in 2017, according to Centrica plc. At peak, the field will contribute five percent of the UK’s total gas production, which is enough to heat the equivalent of 1.5 million homes, Centrica said in a statement sent to Rigzone. Work on the Cygnus project, which commenced in 2012, has already created 5,000 jobs across the country during the construction phase alone. “That 5,000 figure is made up of direct, indirect and induced jobs,” a Centrica spokesperson told Rigzone.

“[This] includes the teams directly employed by ourselves, Engie and Bayerngas, as well as our supply chain partners, but also the additional jobs in the local economy which are supported by work on the project,” he added. As part of Cygnus’ initial job creation process, Heerema Fabrication Group alone employed 700 people to work on the construction of the Cygnus platforms in Hartlepool. Going forward, Engie recently signed a contract extension for Cygnus work with Petrofac and progress has already been made to extend the field via fresh wells being drilled at the nearby Cygnus Bravo platform. “The Cygnus field is hugely important to the country’s energy supply, so we are proud that gas is now flowing from the field and into homes and businesses across the UK,” Chris Cox, managing director of Centrica’s Exploration & Production business, said. “This milestone was only possible thanks to the hard work and collaboration of the teams across Centrica, ENGIE E&P, Bayerngas and our supply chain partners,” he added. Following the start-up of Cygnus, the Oil & Gas Authority praised the collaborative effort of the companies involved.




“Centrica, ENGIE E&P and Bayerngas have demonstrated an impressive collaborative effort in achieving first production from Cygnus. It represents a significant milestone for the Southern North Sea, delivering new volumes through existing infrastructure, utilizing the UK’s skilled supply chain and helping create the right conditions for further developments,” Andy Samuel, chief executive of the Oil & Gas Authority, said.

“This is set to continue with the next phase of development from Cygnus Bravo which will bring additional capacity on stream in the future to help maximize economic recovery for the UK,” he added. Iain Wright, MP for Hartlepool and chairman of the business, energy and industrial strategy select committee also praised the commencement of first-gas from Cygnus. “This achievement underlines just how important North East England is as an energy hub and I welcome the £1.3billion that Centrica and their partners have invested in this project, both in Hartlepool and right across the UK,” he said. Cygnus was discovered in 1988 but it took a government tax allowance of $810 million (GBP 500 million) for large shallow-water gas fields - introduced in July 2012 - before the project could go ahead. Located just over 90 miles off the coast of Lincolnshire, England, Cygnus has estimated gross 2P reserves of approximately 635 billion cubic feet of gas. The Cygnus gas field is operated by Engie E&P UK Limited. Centrica plc owns a 48.75 percent interest in the project.




U.S. natural gas production resilient to market changes in 2015, but has fallen in 2016.. Source: U.S. Energy Information Administration, Natural Gas Annual

U.S. dry natural gas production continued to increase in 2015, reaching 74.1 billion cubic feet per day (Bcf/d). This record-high level was a 4.5% (3.2 Bcf/d) increase over 2014, according to EIA’s Natural Gas Annual, which provides final production data for 2015.

The increase in 2015 production levels marked the tenth straight annual increase, with the most recent increase occurring despite natural gas prices at the Louisiana Henry Hub declining more than 40% from an average of $4.55 per million British thermal unit (MMBtu) in 2014 to $2.62/MMBtu in 2015.




Production gains were highest in Pennsylvania, Ohio, and West Virginia, due in large part to production from the Marcellus and Utica/Point Pleasant shales. These three states accounted for most of the total increase in 2015. Although annual production in 2015 grew, monthly U.S. natural gas production has since declined in 2016, falling to 71.4 Bcf/d in July 2016 after reaching a peak of 75 Bcf/d in April 2015.

Texas remains the largest natural gas producing state, producing 19.4 Bcf/d in 2015. For the third consecutive year, Pennsylvania saw the largest total gain in annual production, increasing to 13 Bcf/d in 2015, up 11.4% from 11.6 Bcf/d in 2014. Ohio saw the largest percentage increase in natural gas production, increasing 49.9%, from 1.3 Bcf/d in 2014 to 2.6 Bcf/d in 2015. Louisiana production declined by the largest amount, falling to 4.8 Bcf/d in 2015, a decrease of 0.5 Bcf/d, or 10.8%, compared to 2014.

Shale gas wells continue to be the largest source of total natural gas production. According to the Natural Gas Annual, gross withdrawals from shale gas wells—which, unlike dry natural gas production, include all compounds extracted at the wellhead—increased from 38.3 Bcf/d in 2014 to 42.4 Bcf/d in 2015, representing 47% of total natural gas production. This increase in production occurred despite declines in natural gas prices.




U.S. oil and natural gas proved reserves declined in 2015 because of lower prices

U.S. crude oil proved reserves declined 4.7 billion barrels (11.8%) from their year-end 2014 levels to 35.2 billion barrels at year-end 2015, according to EIA’s recently released U.S. Crude Oil and Natural Gas Proved Reserves report. U.S. natural gas proved reserves decreased 64.5 trillion cubic feet (Tcf), a 16.6% decline, reducing the U.S. total to 324.3 Tcf at year-end 2015.

The significant reduction in the average price of both oil and natural gas between 2014 and 2015 resulted in more challenging economic and operating conditions, important factors in determining proved reserves.

West Texas Intermediate crude oil spot prices declined nearly 50% from $94.55 per barrel in 2014 to $50.00 per barrel in 2015. The natural gas spot price at the Louisiana Henry Hub declined more than 40% from $4.55 per million Btu in 2014 to $2.62 per million Btu in 2015. These price reductions led to reduced drilling activity and lower reported proved reserves across a broad range of U.S. producers in 2015.

Proved reserves are volumes of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable under existing economic and operating conditions. Because they depend on economic factors, proved reserves shrink or grow as commodity prices and extraction costs change. EIA bases its estimates of proved reserves on an annual survey of domestic oil and natural gas well operators.




Source: U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves

Crude oil and lease condensate reserves decreased in most states in 2015, with the largest net decrease in Texas, followed closely by North Dakota. Texas also had the largest net decrease in natural gas proved reserves.

New Mexico was one of four states that experienced a net increase in proved reserves of crude oil and lease condensate in 2015, mostly from development of the Wolfcamp shale and Bone Spring plays in southeastern New Mexico’s portion of the Delaware Basin.

Ohio added more than 5 Tcf of natural gas proved reserves, mostly from the Utica-Point Pleasant Shale play, and Ohio surpassed Arkansas and the Gulf of Mexico to become the ninth-largest natural gas reserves state.

Source: U.S. Energy Information Administration, U.S. Crude Oil and Natural Gas Proved Reserves




NewBase 19 December - 2016 Khaled Al Awadi

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE

Oil little changed, supply outlook unclear Oil prices were little changed on Monday, with little news to influence a market waiting to see whether U.S. production from shale fields will grow enough to offset planned output cuts by OPEC, Russia and other producers next year.

Brent futures for February delivery were down 24 cents, or 0.4 percent, at $54.97 a barrel by 11:43 a.m. EST (1643 GMT). U.S. West Texas Intermediate crude for January rose 6 cents, or 0.1 percent, to $51.96 per barrel on its last day as the front-month.

"Implied U.S. output increases... will offset a significant portion of the planned OPEC production cuts especially since we don't anticipate sustained strong compliance," Jim Ritterbusch, president of Chicago-based energy advisory firm Ritterbusch & Associates, said in a note.

"While adherence to (OPEC) cutbacks could be quite high initially, we will be surprised by compliance much above 60 percent by the end of the first quarter as (U.S.) shale responds to a higher price environment," Ritterbusch said.

U.S. oil output is expected to increase as energy companies last week continued to add oil rigs, extending a seven-month drilling recovery. "Since its trough on May 27, producers have added 194 oil rigs (+61 percent) in the U.S.," U.S. bank Goldman Sachs said.

As a result, U.S. oil production is edging up, rising from below 8.5 million barrels per day (bpd) in July to almost 8.8 million bpd by mid-December.

A week ago, oil prices climbed to a 17-month high after the Organization of the Petroleum Exporting Countries and some other producers agreed over the prior few weeks to cut almost 1.8 million bpd in oil output starting in January.

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News Agencies News Release 19 Dec. 2016

Saudi Aramco and GE deliver first wind turbine to KS Arabia CNBC - Anmar Frangoul

The first wind turbine has been delivered to the Kingdom of Saudi Arabia and will be commissioned in January 2017, it has been announced.

In a news release on Sunday, Saudi Aramco said the delivery of the turbine marked an "historic milestone for renewable energy" in the oil rich Kingdom.

Saudi Aramco said that it had partnered with GE to show the "viability" of wind power in Saudi Arabia. The turbine will be located in the north west of the Kingdom, in Turaif, and will provide power to Saudi Aramco's Bulk Plant there.

The tips of the turbine's blades will reach 145 meters in height and it will produce 2.75 megawatts of power at its peak, enough energy to meet the needs of roughly 250 Saudi homes, Saudi Aramco said. "Saudi Aramco is actively promoting the reduction of energy intensity across the Kingdom by advocating responsible policies, awareness, and energy innovation," Abdulkarim Al Ghamdi, executive head for power systems at Saudi Aramco, said in a news release. A huge exporter of oil, Saudi Arabia is looking to strengthen its renewable energy credentials. Under the Saudi Vision 2030 plan, authorities there have set themselves the target of producing 9.5 gigawatts of renewable energy by 2030. "With the arrival of the first GE wind turbine in the Kingdom, we are demonstrating our strong commitment to support the aim of diversifying the energy mix," Hisham Albahkali, GE's President & CEO for Saudi Arabia and Bahrain, said.




"This is a momentous occasion as it highlights that wind energy generation in the Kingdom is 'real' and heralds a new era of renewable energy that clearly shows to the world that action is being taken to support the renewable goals of Saudi Vision 2030," Albahkali added. State-run oil giant Saudi Aramco will commission its first wind turbine project next month, the first in the kingdom and developed in partnership with GE aiming to support the renewable goals of Saudi Vision 2030. Supplied by GE, the 2.75-120 wind turbine will provide power to Saudi Aramco’s Bulk Plant located in Turaif, in northwest Saudi Arabia. Abdulkarim Al Ghamdi, Saudi Aramco’s executive head for Power Systems said: “Saudi Aramco is actively promoting the reduction of energy intensity across the Kingdom by advocating responsible policies, awareness, and energy innovation. This milestone has been made possible with the skills and knowledge Saudi Aramco has attained over decades as the Kingdom’s reliable supplier of energy and those of our partner, GE, as a wind industry leader.” Turaif was selected by Saudi Aramco from four potential sites, due to its good wind resource, ease of access, and proximity to power connection. The wind turbine will generate 2.75 mega watts of power at its peak, sufficient energy to sustain around 250 Saudi households. This provides the company the opportunity to reduce burning of diesel for power generation by 18,600 barrels of oil equivalent per year. Hisham Albahkali, GE’s president & CEO for Saudi Arabia and Bahrain, said: “With the arrival of the first GE wind turbine in the Kingdom, we are demonstrating our strong commitment to support the aim of diversifying the energy mix. This is a momentous occasion as it highlights that wind energy generation in the Kingdom is ‘real’ and heralds a new era of renewable energy that clearly shows to the world that action is being taken to support the renewable goals of Saudi Vision 2030.” Once commissioned in January, the wind turbine will present a striking landmark on the Turaif skyline. The tips of the blades will reach a height of 145 meters, or almost half the height of Riyadh’s Kingdom Tower. The diameter of the wind turbine rotor blades will dwarf the span of the world’s largest passenger jet. At 120 meters, the rotor diameter is 50per cent wider than the wing span of an Airbus 380. The wind turbine and its control system have been specifically designed by GE to minimize the potential noise emitted from the rotor blades, the tips of which can travel at one third the speed of sound. GE’s global wind footprint extends to more than 35 countries with over 50,000 mega watts of onshore wind turbines installed across the globe. GE has leveraged this experience to enhance the design of the wind turbine for this project to competently and reliably operate in high temperature, high dust environment within the Kingdom. The wind turbine which arrived to Jubail port in October will be transported on a twelve vehicle convoy from Dammam to Turaif. The construction of the foundations for the turbine are underway and the first electricity is expected to be supplied to the Saudi Aramco bulk plant once commissioning of the wind turbine is completed in January 2017.




The demonstration project has been developed by Saudi Aramco in partnership with GE to highlight the viability of deploying wind power in the Kingdom. Since the inception of its Renewable Energy team in 2010, Saudi Aramco has been actively pursuing opportunities in support of the Kingdom’s goal for the integration of renewable energy in the energy mix. In 2012, Saudi Aramco commenced an extensive resource measurement program that confirmed the Kingdom’s exceptional wind resource as perhaps one of the best in the region. Wind energy will become a key source of power under the National Renewables Program, which will deliver a combined 9,500 mega watts to the Kingdom from wind and solar energy by 2023.




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Khaled Al Awadi is a UAE National with a total of 25 years of experience in the Oil & Gas sector. Currently working as Technical Affairs Specialist for Emirates General 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 Manager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years, he has developed great experiences in the designing & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supply routes. Many years were spent drafting, & compiling gas 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 and Energy program broadcasted internationally, via GCC leading satellite Channels.

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New base 977 special 19 december 2016 energy news