New base 14 january 2018 energy news issue 1127 by khaled al awadi

Copyright © 2018 NewBase www.hawkenergy.net Edited by Khaled Al Awadi – Energy Consultant All rights reserved. No part of this publication may be reproduced, redistributed,

or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this

publication. However, no warranty is given to the accuracy of its content. Page 1

NewBase Energy News 14 January 2018 - Issue No. 1127 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: Zayed Future Energy Award improves lives of 307 million people worldwide

(WAM) -- The Zayed Future Energy Award has contributed to improving the lives of 307 million people around the globe in form of sustainable projects and initiatives launched by the prize winners, including individuals and organiations, according to Dr. Nawal Al-Hosany, Director of the Zayed Future Energy Programme.

In statements to the Emirates News Agency (WAM), Al Hosani said that the prize helped 100 million people around the globe use electricity efficiently, enabling 7.1 million more to have access to potable water at affordable prices.

"The prize also enabled 17 million children to have access to school night classes utilising solar-powered lanterns in addition to enabling 25 million people to make use of modern sources of energy in Africa and Asia, including providing 40 million households with around one billion megawatt/ hour of clean energy generation. She added that the Zayed Future Energy Prize has officially set a Guinness World Record title for the "Largest Environmental Sustainability Lesson."

A total of 282 students from across the UAE took part in the sustainability-themed lesson at the Ritz-Carlton Abu Dhabi, presented by Illac Angelo Diaz, Executive Director of Liter of Light, the non-profit winner of the Zayed Future Energy Prize in 2015.

The 30-minute lecture highlighted how young people around the world can help to reduce energy poverty while also challenging them to devise solutions that will bring about a more sustainable future.

The gathering also saw the assembly of 2,400 solar lanterns, arranged to create a unique light installation in tribute to late Sheikh Zayed, the UAE’s founding father, the centenary of whose birth is being celebrated across the UAE in 2018.

The Zayed Future Energy Prize, launched in 2008, is the world’s preeminent renewable energy and sustainability prize, each year recognising outstanding contributions from companies, schools, non-profit groups and individuals




UAE: AD approves $M25 for projects in Mauritius and Rwanda REUTERS/Stringer + Khaleej Times

The two projects are being financed through the fifth funding cycle of the Irena/ADFD project facility

Image used for illustrative purpose. A view of the solar power plant Shams 1 at Madinat Zayed in Abu Dhabi, UAE.

The Abu Dhabi Fund for Development (ADFD) and the International Renewable Energy Agency (Irena) have earmarked $25 million in ADFD concessional loans for two solar photovoltaic (PV) projects in Mauritius and Rwanda. Announced at the eighth session of the Irena Assembly, the two projects are being financed through the fifth funding cycle of the Irena/ADFD project facility. Established in 2013, the seven-cycle programme offers $350 million to assist developing countries in accessing low-cost capital for renewable energy projects. Since 2014, ADFD has allocated $214 million to 21 projects, attracting over $420 million in co-financing from governments and development funds. Adnan Z. Amin, director-general of Irena, said: "For developing countries, renewable energy is a triple win: It offers a cost-effective means of supplying electricity to families, fuels economic growth and supports energy independence and security. However, many developing countries have trouble accessing funding for renewable energy projects. Our continued partnership with ADFD will provide a stable, low-cost source of financing to help Mauritius and Rwanda achieve a sustainable energy future." Mohammed Saif Al Suwaidi, director-general of ADFD, said: "ADFD's collaboration with Irena aligns with the Fund's core mandate of supporting sustainable socio-economic development across developing countries through financing projects that serve vital economic sectors. The ADFD places high priority on renewable energy as a catalyst of inclusive development."




Russia: Gazprom Neft drills first quadruple multilateral well Source: Gazprom Neft

Gazprom Neft subsidiary Gazpromneft-Yamal has completed construction of Russia’s first ever multilateral well with four horizontal cased-hole side tracks, at its Novoportovskoye field. A total 6,756 metres was drilled, including 4,411 metres drilled in the target strata. The well was constructed in 39 days at a rate of 5.78 days per 1,000 metres.

Drilling horizontally branched wells facilitates a manifold increase in drainage from disjointed low-permeability strata, significantly increasing the oil recovery factor at productive strata and bringing marginal reserves into development without the need to drill additional wells. Russian-produced equipment was used in well construction, retooled in line with the specific geological conditions of the Novoportovskoye field.




Gazprom Neft: Innovations on the Horizon

Today’s oil wells are highly sophisticated and costly facilities. The company’s successful introduction of innovative construction technology is directly linked to the oil production costs, achievements in developing non-conventional and hard-to-recover reserves and extended operation of brownfields with their falling production.

Drilling 2.0

Gazprom Neft has approved its Well Drilling and Completion Technology Development Program. The Program is actually not that new: it is an update on and further elaboration of the document approved in 2015. The previous long-term program comprised of 27 projects. Some of them were implemented while other were canceled since new, better alternatives arose, with 10 projects being moved to the updated Program and a total project number reaching 79.

However, the major difference is not the quantity of projects, but a paradigm shift. «The first revision of the Program discussed investigating and testing individual technology,» Ksenia Antipova, Project Manager for Gazpromneft NTC, said. «While implementing the first revision of the Program, we generated a sizable bank of innovative solutions and got mobilized toward a more focused response to the reservoir challenges by selecting an optimal package of technology.»

In fact, some solutions that are not economically practical when tested separately may prove to be a whole different story in a synergy with another technology. This is the true meaning behind the term «optimal well design» that underpins the main focus of the Technology Program.

«Optimal well design is a range of process solutions aimed at cutting down on well construction time and costs without any compromise on quality while maintaining or increasing the production level,» Yuri Kolesnikov, Head of New Technology for Gazpromneft NTC, explained.

«Development of such optimal designs for varying fields and mining & geological conditions is the major goal of the Program. The Program further covers two more areas: well completion under challenging conditions and technology cooperation. Their goal is to expand the array of technology: Develop and trial balloon the technology that will be further integrated in the targeted comprehensive solutions for various reservoirs.»

Optimize It The Tsarichanskoye Field was the sandbox for the optimal design concept. The major issue with this reservoir is a massive loss of mud during drilling. And there is an unstable clay area beneath the lost circulation zone that cannot be tapped without overcoming the mud loss in the above lying formation.

A conventional approach would take up considerable time and funding thus turning the wells unprofitable. Individual tests of several new technologies didn’t produce the intended outcome.

However, the new way made a tremendous difference. The solution did not lie in an individual technology but in the synergy that provided a footing for the optimal well design for the Tsarichanskoye Field.

The new design envisaged penetration of the lost circulation zone with a cheaper mud then running a casing string down the hole and drilling the lower interval embracing unstable clay and the producing reservoir with oil-based mud. Use of the rotor-controlled system and high performance drill bits supported a notable increase in penetration rate for this interval that would otherwise make such design impossible. The production string in the lower part of the well was




replaced with a liner while the later version embodied a hitherto unused design with two liners hung one after the other that enabled an even further decrease in steel intensity.

This well design significantly cut down on the final construction cost. The cost advantage realized through the technology package is 34 million rubles.

Each field has its own challenges that may be dealt with using a similar but a case-tailored, unique bunch of technology solutions. For instance, using the Fishbones multilateral wells, which reach the individual areas of a highly compartmentalized reservoir, is spot on when developing the B cyclothem in the Messoyakha Field (see the Glossary).

However, the common Fishbones are open hole with no casing, but it would cause a borehole wall caving or collapse leading to a rapidly diminishing well productivity given the Messoyakha geological conditions.

To prevent this from happening, it is necessary to construct the cased Fishbones, the multilateral wells with the lined walls, here. No one has ever constructed such wells in Russia. This is the design that provided a footing for the optimal well design in the East Messoyakha Field.

The optimal design for the Priobskoe Field sees a switch over from the quadruple casing well construction to the dual casing one. It is also envisaged to use the oil-based mud and the rotor-controlled system to readily penetrate the unstable area here. Beyond that, a combined liner of varying diameter pipes never before used by Gazprom Neft will be run down the well.

A similar project but in the somewhat different mining & geological circumstances will be also implemented in Megion, in Western Siberia. It envisages a shift from the triple casing well construction to the dual casing one. Geomechanical modeling to select the drilling mud with the




required density will be instrumental in project implementation to successfully penetrate the challenging intervals.

Such projects place an increased emphasis on substantial engineering efforts and close connections between the disciplines. Apart from the examples mentioned above, the top priority for 2017 is to implement the optimal design projects in such reservoirs as the Eastern Section of the Orenburgskoe Oil & Gas Condensate Field and Novoportovskoye.

Bottomhole Innovation

Another portion of the Program is the well completion under challenging conditions. This part extensively relies on import making development and appraisal of domestic technology as well as reducing its costs, especially pressing. A vital facet of business is to develop the relevant competencies, especially, within the subsidiaries.

The emphasized projects of 2017 include the construction of the TAML1 through TAML4 multilateral wells (see the figure) in Messoyakha, the Novoportovskoye, Gazpromneft Khantos, and Gazpromneft Vostok fields.

«Multilateral completion is a complicated, high technology area that requires considerable resources and a wide range of competencies to grow and evolve,» Philipp Brednev, Well Completion Head for Gazpromneft NTC, remarked. «Developing and making it profitable is an ambitious task that, when implemented, will have a huge positive impact on the business.»




The TAML1 well construction project in the Novoportovskoye field is one of the projects already implemented within the Program. «It is a Russian technology. And it increased the drainage area at a minimum cost that led to a significant improvement in the well’s economic performance,» Philipp Brednev clarified.

One more essential project is underbalanced drilling. Technology is vital for developing the naturally fractured carbonate reservoirs whose fractures open up during well construction triggering a massive loss of mud.

During underbalanced drilling, the wellhead is sealed and the bottomhole pressure is set up below the reservoir pressure thus causing oil to flow to the well and preventing mud from flowing into the formation. «In this way, we aim to increase the number of the open fractures,» Ksenia Antipova explained. «And if now we have to stop when the first fracture has opened up because it sets off loss of mud, this technology will aid in opening as many fractures as the design bore length permits.»

The lateral construction project that keeps the existing bore in operation will be implemented in the Gazpromneft Khantos reservoirs. It will breathe new life into the old wells whose profitability plunged along with their rates. The technology allows keeping oil inflow from the old bore when there is no guarantee of the new bore hitting an economically viable production level.

Inflow control equipment is scheduled for testing in 2017. This technology is vital to develop the under-gas-cap deposits since it prevents gas breakthrough to the oil wells, which is highly common in such fields.

Simultaneously, wells with an ever deepening horizontal bore are under construction. The 2016 all-high record is a two kilometer horizontal well. The 2017 plans provide for construction of a

Novoportovskoye field well with a 2.5-km horizontal section.

Cooperation for Oil Technology cooperation should provide Gazprom Neft with access to the competencies and technology they are otherwise lacking. Besides that, the industry’s existing cutting edge well construction technology gets tweaked to meet the company’s crucial needs.

One example of the project implemented based on technology cooperation is to develop a base oil for oil-based muds that are now growing in demand. For the moment, the oil comprising 65% of




the mud is procured from abroad while its production at the Gazprom Neft plants will slash down the OBM cost by 40–50% and thus bring an upsurge in the drilling efficiency under challenging conditions.

Another project is to test the chemical diverters for a multistage re-fracturing on the wells with falling productivity. A special composition is injected in the wells that previously underwent fracturing to plug the old fractures and form the new ones. The agent decompose with time, and the well returns to operation. In the rest of the world, this technology is used for the low permeability shale reservoirs. The issue facing the cooperation members is to fine-tune the chemical diverter composition to use it for the conventional terrigenous fields.

One more project contemplated to be implemented within the cooperation is to develop a hybrid drilling rig. It is a high technology rig, easy to haul and install. An automated trip system enables a notable increase in penetration rate. The rig will be further equipped with its own coiled tubing that will radically simplify most operations.

The casing drilling project is also scheduled to be implemented in 2017. The technology envisages the use for drilling of the same pipes that will later form the production string of the well. The end of this string has a special turbo shoe on it that both protects / guides its bottom end while running in the hole (as a typical casing shoe) and starts rotating to drill when mud is supplied. The dedicated remotely controlled deflecting rods placed on the bottom of the string are used to deviate the well if necessary.

Among the rest of the close future projects, mention can be made of discovering the best possible surfactants for the formulations for initial penetration. There is some positive experience of their use in the world but so far no universal guidelines as to how surfactants should be selected considering the rock type they are to be used on. The project is aimed at developing such guidelines.

«One of the most essential areas to develop the cutting edge technology is technology scouting,» Alexei Cherepanov, In-House Oil Service Efficiency Program Manager for Gazprom Neft, clarified. «It embraces identification of both new technology and engineering solutions or knowledge of their particular features. It is anything that gives a company an edge over its competitors through a more efficient allocation of resources.»

As estimated by the developers of the Well Drilling and Completion Technology Development Program it will reduce the well construction cost by 20%. As a result, capital costs will go down by 46 billion rubles by 2025, and the company will additionally produce 21 million tons of oil. The previously unprofitable reserves re-entering production will amount to 134 mln. TOE




U.S: Frackers Arise From Oil-Price Rout on a Course to Dominate Bloomberg - David Wethe

The world’s two biggest oilfield service providers, Schlumberger Ltd. and Baker Hughes, are the best performers in the Standard & Poor’s 500 Energy Index this year. Even smaller rivals are cashing in on investor enthusiasm over a 50 percent rise in oil prices since late June.

Enter Liberty Oilfield Services Inc., the Denver-based provider of hydraulic fracturing that climbed 28 percent in its Friday debut as a public company. After pricing its IPO at $17 a share, Liberty jumped to $21.77 in New York trading, boosting its market value to $2.6 billion.

“The timing has turned out well for us,” said Chris Wright, chief executive officer for the 6-year-old company, in a phone interview. “We’re basically a bunch of highly competitive tech nerds that built organically from the ground up a frack company.”

Oilfield-service providers, which oil companies hire to do everything from mapping prospects to maximizing field output, were the first to get clobbered when the worst crude-market crash in a generation kicked off in 2014. They accounted for the largest chunk of job cuts that cast hundreds of thousands out of work and incurred massive financial losses.

Now, the service providers are poised to benefit more than any other subsector of the oil industry, according to Bloomberg Intelligence.

Blasting Rock

One key profit driver for that tranche of companies has been ever-more-complex hydraulic fracturing, or fracking, which entails blasting water, sand and chemicals deep underground to release trapped hydrocarbons, analysts Mark Rossano and Peter Pulikkan of Bloomberg Intelligence wrote in a report Friday.




“Technology is a major part of Liberty’s competitive advantage,” said Wright, a Massachusetts Institute of Technology-trained electrical engineer. “It’s a massive part of the reason for why even in the downturn we grew our business meaningfully in 2015 and 2016.”

Halliburton Co., Schlumberger and closely-held BJ Services are the Big 3 of fracking, each with more than 2 million horsepower in rock-blasting pumps, according to Tulsa-based industry consultant Spears & Associates.

While the size of Liberty’s frack fleet doesn’t crack the top 10, there is one metric where it shines: the company generated the most sales-per-available-horsepower last year at $1,961. Liberty is expanding its fleet and expects to have 1.03 million horsepower by the end of the second quarter, Wright said.

‘Pretty Strong’

Expansion by other frackers is being closely watched. North American fracking capacity probably will grow 8 percent this year to 24 million horsepower, according to Spears. Prices charged for fracking climbed nearly 30 percent last year and are on pace to grow another 5 to 10 percent this year, said Samir Nangia, a director at industry consultant IHS Markit Inc.

“By our view of it, those horsepower additions are still lower than the increase in demand for horsepower this year,” Liberty’s Wright said. “It looks like the frack market will be pretty strong this year.”




NewBase January 14 - 2018 Khaled Al Awadi

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

Oil fourth week of gains, Brent rose 3.3%, WTI jumped 4.7% Reuters + Bloomberg + NewBase

Oil prices rose for a sixth day on Friday after Russia’s oil minister said that global crude supplies were “not balanced yet,” alleviating market concerns about a wind-down of the OPEC-led deal to reduce production.

Russian Energy Minister Alexander Novak said ministers from leading OPEC and non-OPEC producers will discuss the possibility of exiting the deal at a coming committee meeting, but said that “we see that the market surplus is decreasing, but the market is not completely balanced yet.”

His comments boosted prices, which rebounded from earlier decline, though the market has not hit the heights it touched on Thursday, when Brent crude topped $70 a barrel for the first time since December 2014.

Markets remained buoyed by the comments throughout the session, shrugging off data that suggested the U.S. production may continue to surge.

Brent crude futures LCOc1 rose 61 cents to settle at $69.87 a barrel. U.S. West Texas Intermediate (WTI) crude futures CLc1 rose 50 cents to $64.30. WTI hit its strongest since late 2014 at $64.77 on Thursday.

Oil price special

coverage




The agreement between the Organization of the Petroleum Exporting Countries and Russia reached in late 2016 to cut 1.8 million barrels of crude daily is due to last until the end of 2018. Novak said the current oil price was short-term, and he would discuss the situation at a ministerial monitoring committee meeting in Oman, scheduled for Jan. 21.

Russia’s Lukoil Chief Executive Vagit Alekperov said Russia - part of the global agreement with the Organization of the Petroleum Exporting Countries to reduce supply - should start to exit the pact if crude prices remain at $70 a barrel for more than six months.

Major oil producing-countries have grown concerned that as prices remain near these levels, it will spur additional production from U.S. shale patches in Texas and North Dakota, risking overwhelming the market with additional supply, and hurting OPEC’s market share.

Oil Set for 4th Weekly Gain as U.S. Glut Eases on Winter Decline

Oil headed for a fourth weekly gain as the longest run of winter declines for U.S. crude stockpiles in a decade eased an inventory glut.

Futures in New York were trading near the highest close in more than three years and are up 3.6 percent this week. U.S. crude supplies capped an eighth straight drop last week as inventories edge toward the five-year average, according to government data Wednesday. Brent oil in London climbed above $70 a barrel Thursday for the first time since December 2014.

Oil has continued to rally this year after posting a second annual advance as the Organization of Petroleum Exporting Countries and its allies curb supply to drain a worldwide glut. While the global market is balancing, there are still more than 100 million barrels that need to be cleared, according to United Arab Emirates Energy Minister Suhail Al Mazrouei.

“Global oil market fundamentals have reached their healthiest state in several years,” Michael Tran, a commodities strategist with RBC Capital Markets in New York, wrote in a note. “While we anticipated a firm rebound in the second half of 2017, current price action has surpassed our




expectations. We believe that it is premature to expect further upside to be sustainable, at least until the market gains a better grasp of the pace of U.S. production growth.”

West Texas Intermediate for February delivery was at $63.65 a barrel on the New York Mercantile Exchange, down 15 cents, at 10:10 a.m. in Hong Kong. Total volume traded was about 17 percent above the 100-day average. Prices gained 23 cents to $63.80 on Thursday, the highest close since December 2014.

Brent for March settlement added 2 cents to $69.28 a barrel on the London-based ICE Futures Europe exchange after rising 6 cents on Thursday to the highest close in three years. Prices are up 2.5 percent this week. The global benchmark traded at a premium of $5.73 to March WTI.

Surging Commodities as Oil Tops $70

Investors are betting there’s more to come from commodities after a surge in industrial metals and oil prices.

Assets invested in commodity-linked securities climbed to a four-year high of $311 billion after increasing 1 percent in December, according to Barclays Plc. Net inflows of $3.4 billion outweighed losses of $300 million last month, signaling bullishness.

“Rising manufacturing confidence in many regions continues to spur commodity demand growth,” Warren Russell, a New York-based analyst at Barclays, said in a note to clients. “Strong economic activity is set to continue in 2018.”

The return of global growth, manufacturing output and supply constraints have whetted investor appetites at a time when stock and bond valuations are high. Brent crude topped $70 a barrel in London on Thursday for the first time in three years, just days after zinc touched a 10-year intraday high. Copper’s turn was late last month, when it reached levels last seen almost four years ago. Still, the big risk for commodities is, as ever, the world’s second-largest economy, Russell said. “China’s expected slowdown should mean that recent strength in oil and copper is unlikely to last.”




It's Already Time to Start Thinking About Oil in 2019 By Liam Denning

I know the year's barely started, but it's already time to start thinking about 2019.

The reason is the oil rally that has taken West Texas Intermediate back above $60 a barrel; Brent to about $70; and analyst chatter to the rarefied realm of $80. Focusing in on WTI, there's been a big shift in the futures curve over the past six months:

Liquid Slope

The WTI crude oil futures curve has shifted significantly in the past six months

Source: Bloomberg

I wrote here last month about the surge in hedging by North American exploration and production companies during the third quarter of 2017. At the end of June, 53 firms analyzed by Bloomberg New Energy Finance had collectively hedged about 636,000 barrels a day, or 12 percent, of their expected oil production in 2018. Three months later, that had risen to more than 1.5 million barrels a day, or 29 percent, with hedging weighted toward the first half of 2018 in particular.

Hedging for 2019 was still relatively scarce, though: As of the end of September, only 200,000 barrels a day, around 3 percent, of expected oil production was hedged, according to BNEF's database. That isn't unusual; you wouldn't really expect E&P companies to be hedging a lot of production 18 months or more in the future.

Now that New Year's Day 2019 is less than 12 months away, though, E&P companies may well be considering locking in hedges for next year, especially in light of that recent rally.




Swaps for 2019 are now around $57.50 a barrel, almost $8 a barrel higher than where they traded in the third quarter, and with almost half that gain coming in the past month alone.

Golden Years

Crude oil swaps for 2019 have rallied strongly since the summer, taking them to their highest level in more than two years

Source: Bloomberg

Those eight bucks are significant, equivalent to the average cost of infrastructure and corporate overhead per barrel for the top 30 producers in the Permian basin, according to a presentation given in November by Rystad Energy's VP of analysis, Artem Abramov. He pegged the averaged full-cycle cost there at about $54 a barrel.

Meanwhile, the average prices locked in by Permian operators via hedges in the third quarter were about $49 for 2018 and about $52 for 2019. It should also be noted that current swaps prices are higher than where they were in late 2016 and early 2017, when E&P firms rushed to hedge last year's output in the initial celebratory period after OPEC first announced supply cuts.

The upshot being that $57.50 represents an attractive point for E&P companies to start locking in hedges for 2019 already.

There are some clues suggesting this is happening. The net short position of swaps dealers in WTI crude oil futures and options -- a proxy for E&P hedging -- has expanded by a notional 250 million barrels since the end of the third quarter, with that trend continuing into 2018.

Meanwhile, energy economist Phil Verleger noted in a recent report that open interest in the three main crude oil futures contracts expiring in more than one year stands at 1 million contracts (a notional billion barrels), versus just 800,000 contracts a year ago. The implication being that producers are locking in hedges on 2019 production more aggressively than they were doing for 2018 a year ago.

Verleger estimates this translates to an increase in U.S. oil production of at least 600,000 barrels a day in 2019, which is slightly higher than the initial projection from the Energy Information Administration, released earlier this week.




We won't get the full picture until both fourth-quarter and first-quarter earnings are out of the way, roughly by the beginning of May. It seems likely that E&P companies will have taken the opportunity to take some risk off the table for 2019. If it turns out they haven't, then that would imply some pretty bullish thinking about the oil market next year.

Oil's Path to $70 Defied Pressures That Still Threaten Prices

Oil’s rise to $70 a barrel for the first time in three years had clear triggers as supplies tighten and demand climbs, yet it still surprised many traders because there were so many reasons for prices to falter.

Those bearish pressures are still in place, and could make it tough for crude to hold onto its gains.

Stockpiles Grow Again

One thing the major forecasters agree on is that, after shrinking dramatically in 2017, oil stockpiles should be starting to build up again.

Global oil demand dips seasonally as the need for winter fuels recedes, and data from both OPEC and the International Energy Agency suggest that will tip the market back into surplus in the first half of this year. Inventories will shrink again in the second half, their data indicate.

Oil Surplus Returns

Both OPEC and IEA forecasts suggest stockpiles will grow again in 1H

While weekly U.S. data shows that crude inventories are declining, it’ll be another couple of months before a clear picture for other consumers emerges.

Disruptions Fade

Supply disruptions boosted prices in early December, when a critical North Sea pipeline was halted, and at the end of the month when a pipeline explosion curbed flows from OPEC member Libya.




The suspension of the Forties Pipeline System -- one of the North Sea’s biggest disruptions since the 1980s -- was resolved by the end of last month, and repairs on the conduit to Libya’s Es Sider terminal were completed about the same time. Yet the resolution of both outages did little to push prices lower.

Risks to production still remain, though, with Goldman Sachs Group Inc. considering Venezuela and Nigeria to be among the most vulnerable.

Political Dangers Recede

Political risks in major oil producers also bolstered the market, yet as these stabilized or receded prices still stayed strong.

A corruption crackdown by Saudi Arabia’s Crown Prince Mohammed bin Salman in early November sparked concerns the world’s biggest oil exporter would suffer a backlash and instability that didn’t materialize.

An even bigger boost came last month when Iran, OPEC’s third-largest producer, faced its biggest street protests in almost a decade amid discontent with the country’s economic stagnation. Though these didn’t escalate or threaten oil facilities, crude prices didn’t fall back.

Another risk to Iranian exports appears to have been dodged as U.S. President Donald Trump backs away from tearing up an accord on Iran’s nuclear program, which would have slapped American sanctions back on oil shipments.




EIA forecasts mostly flat crude oil prices and increasing global production through 2019…: U.S. EIA, Short-Term Energy Outlook, Jan. 2018

EIA’s January Short-Term Energy Outlook forecasts Brent crude oil to average $60 per barrel (b) in 2018 and $61/b in 2019, slightly higher than the $54/b average in 2017. In both 2018 and 2019, EIA expects total global crude oil production to be slightly greater than global consumption, with U.S. crude oil production increasing more than any other country.

Because crude oil prices are expected to be relatively flat through 2019, U.S. gasoline prices are also expected to remain near current levels. EIA forecasts the U.S. average regular retail gasoline price will average $2.57/gallon (gal) in 2018 and $2.58/gal in 2019, slightly higher than the $2.42/gal average in 2017.

EIA forecasts the West Texas Intermediate (WTI) crude oil spot price will average $55/b in 2018 and $57/b in 2019, or $4/b and $5/b, respectively, lower than Brent prices. This price difference is expected to narrow from the $6/b average price difference seen in the fourth quarter of 2017 because current constraints on the capacity to transport crude oil from the Cushing, Oklahoma storage hub (the geographic location associated with the WTI price) to the U.S. Gulf Coast are expected to gradually lessen.

As Asian demand for crude oil and petroleum products increase, supply considerations to transport crude oil to Asia are increasingly part of the price formation for global crude oil benchmarks.

EIA estimates that, absent significant pipeline constraints, moving crude oil from Cushing, Oklahoma, to the U.S. Gulf Coast typically costs about $3.50/b. Moving that crude oil from the United States to Asia costs approximately $0.50/b more than to ship Brent from the North Sea to Asia. Although more crude oil export infrastructure has been recently built, U.S. exporters must still use smaller, less-economic vessels or more complex shipping arrangements, which often add to costs.




EIA estimates that the implied global stock change (the difference between total world consumption and total world production) averaged 0.4 million barrels per day (b/d) in 2017, marking the first year of global inventory draws since 2013. EIA expects global inventories to increase by about 0.2 million b/d in 2018 and by about 0.3 million b/d in 2019.

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, January 2018

Crude oil production from the Organization of the Petroleum Exporting Countries (OPEC) averaged 32.5 million b/d in 2017, a decrease of 0.2 million b/d from 2016. The decline was mainly a result of the November 2016 OPEC production agreement that aimed to limit OPEC crude oil output to 32.5 million b/d.

OPEC and non-OPEC participants agreed on November 30, 2017, to extend the production cuts through the end of 2018 in an effort to reduce global oil inventories. EIA expects OPEC crude oil




production to increase by 0.2 million b/d in 2018 and by an additional 0.3 million b/d in 2019 as it slowly returns to pre-agreement levels.

Crude oil production from the United States is expected to increase more than in any other country. U.S. crude oil production is forecast to average 10.3 million b/d in 2018, marking the highest annual average production in U.S. history, surpassing the previous record of 9.6 million b/d set in 1970. U.S. crude oil production is expected to continue increasing in 2019 to an average of 10.8 million b/d.

Global consumption of petroleum and other liquid fuels grew by 1.4 million b/d in 2017, reaching an average of 98.4 million b/d for the year. EIA expects consumption growth will average 1.7 million b/d in 2018 and 1.6 million b/d in 2019, driven by the countries outside of the Organization for Economic Cooperation and Development (OECD). Non-OECD consumption growth is expected to account for 1.2 million b/d and 1.3 million b/d of the growth in 2018 and 2019, respectively.




NewBase Special Coverage

News Agencies News Release January 14-2017

Why a Natural Gas Tanker Is Looking for Your Car By Anna Shiryaevskaya

One thing the world has now in abundant supply is natural gas -- liquefied natural gas in particular. To increase demand, producers want to put the fuel into cars, trucks and ships that currently use gasoline, diesel or fuel oil, which are dirtier and cost more.

If natural gas catches on, look for it first in fleets of small trucks, cars and buses from China to Italy, as well as in giant ocean-going vessels. Natural-gas proponents say their technology could be a bridge to a future dominated by electric vehicles, though mass adoption of natural gas-powered cars faces steep hurdles.

1. Can I buy a vehicle that uses natural gas?

Probably, depending on where you live. There are more than 24 million natural-gas vehicles in use worldwide, including about 160,000 in the U.S. Any vehicle, from a passenger car to a truck to a train, can use the fuel, if it’s built that way, or converted.




While many manufacturers "offer factory-built natural-gas trucks, step-vans, transit buses and school buses, there are fewer options for consumers who need light-duty cars, vans and pickup trucks -- but the market is starting to turn," according to CNG Now, an industry advocacy group. There are natural-gas versions of the Honda Civic and the Ford F-250 pickup, for instance.

2. How do natural gas-powered vehicles work?

They’re powered by internal-combustion engines, just like gasoline-powered cars. There are two major ways to use natural gas as a fuel. Compressed natural gas (CNG), the most common form, is delivered to filling stations through pipes and compressed before being pumped into specially designed fuel tanks.

Liquefied natural gas (LNG) is a more complex product. Gas becomes a liquid, and its volume shrinks by 600 times, when it’s chilled to minus 162 degrees Celsius (minus 260 Fahrenheit). The costly infrastructure needed to keep the gas cold restricts its use primarily to shipping and to large trucks. Besides natural gas, there’s also a renewable form known as bio-gas, or biomethane, harvested from organic waste matter.

3. Where are the biggest markets?

China, battling some of the worst air pollutionin the world, leads the planet in natural-gas vehicles. It has a long history of using LNG as a truck fuel in some central and western provinces, where companies set up small liquefaction plants to convert locally produced gas.

LNG-fueled truck sales in China jumped sixfold in the first half of 2017 over the previous year, as policy changes favored the cleaner-burning fuel, according to Wood Mackenzie Ltd. Beijing in September 2017 banned older diesel trucks from parts of the city from 6 a.m. to midnight daily.

By one estimate, China should represent almost half of the global market in 2035. California, meanwhile, produces so much biomethane that it can displace about 25 percent of diesel used for transportation there, according to California Natural Gas Vehicle Coalition. Another promising market is India, where, according to Allen Abraham, an analyst at Bloomberg New Energy Finance, consumers would choose a CNG vehicle over an electric one if there’s access to CNG fueling stations (though most consumers would still prefer petrol or diesel.)

4. What are the obstacles to widespread use of natural gas?

The biggest is the lack of infrastructure -- pipes for delivery and compressors or freezers for fueling. In addition, LNG vehicles need equipment to keep the fuel cold. An LNG station may cost up to $4 million and a large CNG site as much as $1.8 million, according to the U.S. Department of Energy.

Converting your car to run on CNG would also come at a cost. The limited number of filling stations remain an obstacle to the expansion of the technology. In Europe, the authorities are helping fund the development of the network and proposing that by 2020, LNG refueling stations are installed every 400 kilometers (248 miles) and CNG stations every 150 kilometers.

5. What’s the appeal?

For countries trying to meet their climate change pledges under the 2015 Paris agreement, natural-gas vehicles produce less greenhouse gas emissions than their gasoline and diesel counterparts. For consumers, natural-gas engines last longer, and the fuel is as much as 50 percent cheaper than diesel.




In marine shipping, the change is being driven by new international pollution rules that will limit the sulfur content of fuels to 0.5 percent in 2020 from 3.5 percent today. One large container ship at sea emits as much sulfur oxide emissions as 50 million diesel cars.

6. Isn’t electricity the real future for cleaner cars?

Probably, which is why some natural-gas proponents hope only to be a bridge to that future. Under this line of thinking, natural-gas cars and trucks stand a chance to be ascendant over the next 15 or 20 years -- a period of time when reducing emissions will be a global priority -- before being overtaken by cars that are plugged in.

7. How realistic is that?

Natural gas stands its best chance to be a go-to fuel choice in ships, a decent chance in trucks, and faces a challenging path when it comes to cars. Electric vehicles account for only 1 percent to 2 percent of total vehicles sales in most markets, but sales are picking up for some automakers.

EVs already hit around 3.4 percent of total sales for BMW in the first three quarters of 2017, and sales by Chinese automakers are even higher, according to Bloomberg New Energy Finance. In Europe, electric vehicles dominate sales of alternative fuel vehicles.

While registration of gas-powered cars increased by 13 percent in the third quarter, battery, hybrid and plug-in electric cars each showed gains of more than 50 percent, according to the European Automobile Manufacturers Association.

EVs or CNGs?

The debate has raged for years in alternative transportation. Electric vehicle (EV) advocates claim that the steady improvement in battery technology, the pervasiveness of the grid, and software




and services to enable things like high-speed charging will make electrification of at least some portion of the transportation market inevitable.

Tesla Motors CEO Elon Musk predicts that 13 percent or more of cars coming off production lines could be electric by 2020 while Nissan’s Carlos Ghosn says 20 percent of its cars by 2020 will be electrics, and that doesn’t count standard hybrids, which are partly electric.

Electric will even play a role in public transportation, argues Proterra, which has created an electric bus for municipal transportation and a complementary high-speed DC charger that can get its 68-passenger behemoths back on the street in 20 minutes or less.

CNG advocates, however, claim they have a big advantage on their side: reality. CNG

cars already exist and natural gas, thanks to hydraulic fracturing, could remain relatively cheap for some time.

Who is right? To be honest, both. EVs and CNG vehicles will percolate into the market over the next ten years depending on the circumstances. Here’s a general roundup of the pluses and minuses.

1. Efficiency.

EVs tend to win hand down in this category, primarily because the large natural gas-burning turbines at power plants remain far more efficient than the small ones squeezed into cars. A 2010 report from MIT states:

While both EVs (electric vehicles) and NGVs (natural gas vehicles) have significant infrastructure requirements, there are major differences in their relative efficiencies. An NGV does not have comparable efficiency gains relative to electrification via natural gas generation.

In general, 1,000 cubic feet (cf) of natural gas, converted to electricity, yields 457 miles in an EV. This same 1,000 cf in an NGV would only have a range of around 224 miles. (The quote comes from page 24 of the study.)

A 2006 paper by Marc Tarpenning and Martin Eberhard, the first two of the five people listed as founders at Tesla Motors, found natural gas vehicles less efficient than hydrogen, hybrids, gas, diesel and electrics. Yes, Tarpenning and Eberhard are EV proponents, but the numbers work.

Proterra’s all-electric bus gets between 17.5 to 29 miles per gallon, according to the company. Even if you take 20 mpg as a estimate, that beats the 3 to 4 mpg for CNG buses, according to the Department of Transportation. (page 11).

2. Filling Stations.

Again, it’s an EV victory. A 240-volt charger, which can charge a car within 3 to 8 hours, costs $2,000, including installation, according to Colin Read, vice president of corporate development at Ecotality.




“DC fast chargers are currently around $50,000 with installation, although these prices are anticipated to come down greatly,” Read added.

A CNG filling station, by contrast, costs around $750,000, says Bruce Russell, director of communications at Clean Energy Fuels, which builds CNG stations. The price includes compression equipment, typically planted underground, tanks and dispensers, hardware not needed in EV charging stations.

(Note: this is for a commercial filling station. Some companies sell home filling units that go for $4,000, which is still more than electric counterparts. And you're dealing with actively compressing gas in neighborhoods.)

The high price of the filling stations means that CNG cars will likely be purchased by fleet owners for the foreseeable future. Fleet cars drive in somewhat predictable orbits relatively close to home base, which cuts down on the need for filing stations.

Clean Energy, however, hopes to take the sting out of the pricing and expand usability with portable and modular filling stations. It installed its first one, which can accommodate ten vehicles at once, in Chilliwack, Canada last month. (see photo.)

“It is all on wheels. It just needs an electrical connection and a gas connection,” Russell said. “It is going to widely expand the fueling opportunities.”

In all, the company built 68 filling stations in 16 states last year, including five LNG stations.

3. Vehicle Cost.

Call it a toss-up. The all-electric Ford Focus starts at $39,200 before $7,500 in federal tax credits and state credits that can come to a few thousand. So call it $31K. A standard Focus ranges in price from $16,500 to $22,000.

Ford does not make natural gas cars, but some of its cars can be retrofitted into natural gas machines for around $10,000, said Gerry Koss, fleet marketing manager at Ford. That puts it in the high $20K and low $30K range.

Making cars that run natively on natural gas reduces the cost, although only a few manufacturers make these and when they do they are in small numbers. (Some of these are probably subsidized too, similar to the way Mitsubishi sells its all-electric for $29,000.) But batteries are coming down too and EVs require less maintenance than combustion cars of any stripe.

4. Fuel costs.

Electrics win—it only takes a fuel of electricity to go a mile--but CNG cars perform well. A CNG car operates on the equivalent of $2 per gallon of fuel. Since both save over petroleum and diesel, both will ultimately be attractive. Other factors on the list may weigh more in importance such as…

5. Range.

This is where CNG begins to shine. A four-door CNG taxi with a tank that can hold the equivalent of 15 gallons of fuel can get close to 300 miles on a tank. 200 miles is easy. Most mid-range and economy-level EVs like the Nissan Leaf get almost 100 miles on a charge.

“It is not practical for that type of industry to use an EV,” said Koss. “What are the choices? CNG provides a good alternative.”

Long range is also making liquefied natural gas a growing option in ppen water shipping and long-haul trucking. Sure, an LNG filling station might run you $1.2 to $1.5 million (Clean Energy Fuels’




estimate), but try to run a big rig on batteries. They weigh far too much: the batteries would add tons to the hauling mass. The company is currently conducting a pilot with Flying J truck stops to co-locate LNG spout at diesel stations.

Payback is easy to measure too, Russell says. A big rig might consume 20,000 gallons of fuel a year. If natural gas costs the equivalent of $2 per gallon, the driver or trucking company can saves $40,000 a year. A garbage truck might consume 10,000 gallons a year and cost $15,000 to retrofit. The retrofit pays for itself in less than a year and the truck might last seven years.

6. Charge Time.

It takes only a few minutes to fill a CNG car. EVs can take hours.

So how will the debate shape up? The deciding factor could be fast DC charging. Fast charging papers over arguably the two biggest drawbacks on EVs—range and charge time—and it doesn’t depend on scientific breakthroughs in chemistry or physics like bringing down the cost and boosting the performance of batteries will require.

Fast charging requires money and regulatory help: electricity rates were not created to accommodate the burst-type consumption needed for fast charging.

And because power lines and transformers already criss-cross the country, it might be easier than trying to build a CNG superhighway. The fact that T. Boone Pickens and others have been lobbying for handouts from the Federal and state governments for natural gas indicates that the infrastructure for methane could get expensive.

Then again, heavy-duty vehicles may never be amenable to electric drive. They can be outfitted with micro-hybrid units to help cut gas during stops and starts, but may ultimately always rely on liquid fuel.

And it could take years for many fleet owners to get over range anxiety. A government agency that needs cars to check out municipal softball fields might be able to get by with electrics, but taxi routes are unpredictable. The passenger that gets in at O’Hare Airport might need to go downtown, or to Northern Indiana.




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Khaled Al Awadi is a UAE National with a total of 28 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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