New base energy news 07 january 2019 issue no 1222 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,
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NewBase Energy News 07 January 2019 - Issue No. 1222 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: Abu Dhabi adopts ‘business continuity policy’ for energy sector
WAm + The UAE’s Department of Energy (DoE)
UAE has adopted the "Business Continuity Policy" for the energy sector with the aim of enhancing
performance and ensure a safe and sustainable supply in the energy sector, a media report said.
The move is part of the Department’s efforts to increase preparedness among entities operating
within the energy sector to deal with emergencies and crises, in accordance with the standards set
by the National Emergency, Crisis and Disaster Management Authority, reported state-run Wam.
The Business Continuity Policy is one of the first regulations issued by the DoE since its
establishment in February of this year. The Department is tasked with ensuring the effective
management of emergencies, crises and disasters for the energy sector in the Emirate of Abu
Dhabi, in accordance with the provisions of Law No. 11 of 2018 on the Establishment of the
Department of Energy, as well as federal and local legislation governing business continuity and
management of emergencies, crises and disasters.
The adoption of the Policy follows extensive deliberations and coordination efforts with all entities
operating in the energy sector across the emirate. The Department of Energy organised several
workshops in September and December 2018 to discuss the challenges facing the "Business
Continuity Management Programme", as well as draft regulations for the continuity of the energy
sector.

Awaidha Murshed Al Marar, DoE chairman, said: "Adopting the Business Continuity Policy and
cancelling the instructions issued back in 2014 form part of our efforts to upgrade the energy sector
in Abu Dhabi and establish a unified ecosystem that manages business continuity in the industry,
in close coordination with local and federal entities operating in the sector. Our objective is to
develop a unified framework for implementing, within our sector, the standards issued by the
National Emergency, Crisis and Disaster Management Authority."
"We are also looking to outline the roles and responsibilities to be assumed by entities operating
under the Department of Energy’s umbrella in the event of errors or crises. This, in turn, ensures a
sustainable world-class supply of energy services for companies and individuals, facilitating the
adoption of advanced technologies and smart services," Al Marar added, thanking the entities that
played an effective role in launching the Policy.
"The energy sector in the Emirate of Abu Dhabi boasts global status and prestige. Maintaining the
sector’s competitive advantages is our top
priority, given its role in implementing the
Abu Dhabi Economic Vision 2030," he said.
"We urge all companies operating within the
sector to abide by this policy, and work
towards coordinating with all entities
concerned with business continuity, most
notable of which is the National Emergency,
Crisis and Disaster Management Authority."
The Department of Energy will be tasked
with overseeing the implementation
procedures and ensuring that business
continuity standards are maintained, in
accordance with the mechanisms outlined
in the Policy.
The National Emergency, Crisis and Disaster Management Authority issued the second edition of
the Business Continuity Management Standards in 2015 to be implemented nationwide and across
all sectors and facilities, which helps prevent any interruptions of vital activities in the event of an
error of malfunction.

Morocco: Sound Energy-update on the Greater Tendrara permit
Sound Energy, the Moroccan focused upstream gas company, has announced a further update on
the Company's TE-10 exploration well following the identification of gas bearing sands within and
below the currently mapped TAGI structural closure, which potentially materially de-risks the
stratigraphic upside in North East Lakbir in the Company's Greater Tendrara license area.
The North East Lakbir stratigraphic trap had a pre-drill mid case potential on a gross (100%) basis
of 2.7 Tcf gas originally in place ("GOIP") (4.5 Tcf GOIP upside case and a 1.5 Tcf GOIP low case)
and the smaller TAGI structural closure had a mid case potential, on a gross (100%) basis, of 128
Bcf GOIP (210 Bcf GOIP upside case and a 75 Bcf low GOIP case).
The Company also confirms the achievement of total depth ('TD') with TE-10, the potential
identification of additional thin bedded net pay and the successful recovering of a gas sample to
surface.
Source: Sound Energy

The TE-10 well was the second in Sound Energy's current three well exploration programme in the
Tendrara area designed to explore three geologically-independent plays and to establish the
potential of the basin. The well is located approx. 25 kms to the northeast of the recently awarded
Tendrara production concession, which contains the TE-5 Horst discovery unlocked by Sound
Energy in 2016-17.
The TE-10 well has been drilled to a TD at 2,218m measured depth ('MD'), 209m MD below the
base of the TAGI sandstone sequence, in an, as yet, undated section of mudstones and minor thin
bedded sandstones, with gas shows down to 2,070m MD.
The Company announced the preliminary results of the intermediate TE-10 logging results on 27
December 2018, which included a potential TAGI gross reservoir sequence from 1,899m MD to
2,009m MD and an initial net pay estimate of up to 10.5m, with an average porosity of 8%.
The Company has now completed the FMI (high definition formation micro-imager log) which
provides a microresistivity image of the well bore at a much finer resolution than the initial logging
suite. Significantly, the FMI has potentially identified the presence of additional thin bedded net pay
within the previously identified potential gross reservoir interval between 1,899m MD to 2,009m MD.
Quantification of the overall net pay is underway and will require substantiation from side-wall core
analysis and further wireline log evaluation.
The Company is also very pleased to confirm that a gas sample (comprising C1 to C5 hydrocarbons)
was successfully recovered from one of these pay intervals at approximately 1,937m MD using a
MDT (modular formation dynamics tester system). The successful retrieval of this gas sample
confirms the presence of moveable hydrocarbons in the reservoir, and importantly is the first
successful MDT gas test from the TAGI sandstone in the Tendrara licence (where testing has
historically been hampered by the tight nature of the sandstone).
Following the acquisition of the VSP (vertical seismic profile), the Company can confirm that the gas
shows observed extend below the currently mapped structural closure at approximately 1,958m
MD. This suggests the gas accumulation may extend updip into the stratigraphic trap. Seismic
interpretation and modelling is underway to assist with internal estimates of gas resources within
the discovery.
With drilling operations now concluded, plans are now in progress to conduct a well test over the
reservoir interval. This is expected to occur during February 2019, after rig de-mobilisation and
mobilisation of the necessary testing equipment.

Saudi-Petronas RAPID refinery starts trial runs at crude oil unit
Reuters + NewBase
Malaysian state oil company Petronas has started trial runs at the crude distillation unit (CDU) at a
joint-venture refinery with Saudi Aramco in Malaysia, two sources with knowledge of the matter said
on Monday.
Crude oil was fed into the CDU at the 300,000 barrels-per-day refinery at end-December, one of the
sources said. The company also received its second cargo of 2 million barrels of Saudi crude last
week, according to the sources and data on Refinitiv Eikon.
Saudi Aramco pours $7bn into Malaysian petrochemical project
Saudi Aramco and Petronas signed a $7 billion petrochemical deal on Feb. 28-2017.
The share purchase agreement will give Saudi Arabia's state oil company a 50% stake in Petronas'
Refinery and Petrochemical Integrated Development, or RAPID, project. Both King Salman
Abdulaziz Al Saud and Malaysian Prime Minister Najib Razak witnessed the signing in Kuala
Lumpur.
Spread across a 25-sq.-km area, RAPID will
boast the capacity to refine 300,000 barrels of
crude a day into gasoline and diesel, once it is
completed in 2019. Its petrochemical facilities
will be capable of producing 3.5 million tons of
products annually. Petronas said its
Pengerang Integrated Complex, which houses
these facilities, is 60% completed.
Besides supporting the project through bridge
loans, Saudi Aramco is expected to supply up
to 70% of the crude feedstock for the refinery.
The company said it made the final decision to
invest after weighing Malaysia's potential for
growth, as well as its location in Southeast
Asia.
"We see Malaysia as a market and platform for us to target Southeast Asia and the Asian region,"
said Khalid al-Falih, the company's chairman.
Both sides denied earlier reports that the deal had stalled. "From the beginning, we came with the
intention to stay and have a strong partnership with Petronas," said Amin H. Nasser, Saudi Aramco's
president.
The project is expected to give Saudi Aramco, the world's largest oil producer, a shot in the arm
ahead of an estimated $100 billion initial public offering next year. "We believe [the project] will
strengthen the equity story of Saudi Aramco [when] it goes public next year," al-Falih said.
Saudi Aramco, a predominantly upstream player, said joining hands with Petronas will enable it to
meet regional demand for chemicals. "Saudi Aramco is going to grow into an energy company with
a much broader portfolio in the downstream and other energy areas in the years to come," al-Falih
explained.
Al-Falih, who is also Saudi Arabia's minister of energy, industry and mineral resources, said he will
encourage the private sector to invest further in the region, in line with his country's Vision 2030
plan for reducing its reliance on oil revenue.

US top world oil producer, foced oil prices end the year lower
Source: U.S. Energy Information Administration and Bloomberg
Brent crude oil averaged $72 per barrel (b) in 2018, and West Texas Intermediate (WTI) averaged
$65/b in 2018. The prices for both crude oils finished the year lower than they began it. Brent and
WTI each hit their highest prices during the year on October 3 at $86/b and $76/b, respectively.
Prices for each benchmark fell quickly after that, and on December 24, Brent reached an annual
low of $50/b and WTI reached an annual low of $43/b.
Brent ended the year at $54/b, $13/b lower than it began the year, and WTI ended the year at $45/b,
$15/b lower than it began the year. This year marks the first time since 2015 that crude oil prices
for these benchmarks ended the year at a lower price than at the beginning of the year.
U.S. highlights
 U.S. crude oil and other liquids production increased in 2018, and EIA forecasts it to average
17.8 million barrels per day (b/d) for the year, the highest level on record (EIA data going
back to 1994 ) and an increase of 2.2 million b/d from the 2017 production level.
 The United States surpassed Russia and Saudi Arabia earlier in 2018 to become the largest
crude oil producer in the world based on monthly data. U.S. crude oil production was at
record levels in 2018, and in the December Short-Term Energy Outlook, EIA forecasted that
2018 annual crude oil production would reach 10.9 million b/d, surpassing the previous
annual high of 9.6 million b/d set in 1970.
 U.S. crude oil exports averaged 1.9 million b/d in 2018, about twice the amount that was
exported in 2017. Crude oil overtook distillate as the largest U.S. petroleum export.
 The growth in U.S. exports of crude oil and petroleum products led to a one-week period in
late November when the United States was a net exporter for the first time in EIA’s data
history.

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, December 2018
Note: December 2018 data for the United States and Russia are forecasted; EIA does not publish forecast data for
individual OPEC members.
International highlights
 EIA forecasts that the Organization of the Petroleum Exporting Countries (OPEC) total crude
oil and other liquids production will average 39.2 million b/d in 2018, down slightly from 39.3
million b/d in 2017.
 Although U.S. sanctions on Iran began on November 5, 2018, the United States granted
waivers for some of Iran’s largest customers to continue importing limited volumes of crude
oil for six months.
 Crude oil production increases in Saudi Arabia in the second half of 2018 partially offset
Iran’s declining production as a result of the U.S. sanctions on OPEC’s total production levels.
 Russian crude oil and other liquids production increased from an estimated 11.2 million b/d
in January to a forecasted 11.6 million b/d in December.
 In an effort to limit excess supply, on December 7, 2018, OPEC and other producing
countries (including Russia) announced they would cut production by 1.2 million barrels per
day (b/d) from October 2018 levels during the first six months of 2019.

NewBase 07 January 2019 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil Extends Gains as Fed Signals Flexibility and U.S. Rigs Drop
Bloomberg + Reuters + NewBase
Oil is headed for its longest rally in more than 17 months as the U.S. Federal Reserve sought to
soothe investor concerns and on signs of slowing American production.
Futures in New York rose as much as 2.1 percent, and are set for the longest winning streak since
July 2017.
Brent for March settlement increased 1.8 percent, or $1.02, to $58.08 a barrel on the ICE Futures
Europe Exchange in London. Futures surged 9.3 percent last week, the biggest jump since
December 2016. The global benchmark crude traded at an $8.89 premium to WTI for the same
month.
Crude recovered slightly this month after posting its first annual loss since 2015. While Goldman
Sachs Group Inc. cut its oil price forecasts for 2019, citing a re-emerging glut and resilient American
shale output, the bank said a 42 percent drop toward the end of last year was excessive. Volatility
Oil price special
coverage

persists as the U.S. and China try to negotiate an end to a trade war that risks hurting economic
growth and OPEC and its allies pursue supply curbs.
A further step by China’s central bank late Friday to secure liquidity to the slowing economy also
helped assuage some investor concerns. American and Chinese officials will begin negotiations on
Monday in the hope of reaching a deal during a 90-day truce in the trade war between the
administrations of President Donald Trump and counterpart Xi Jinping.
Meanwhile, the number of rigs targeting crude in the U.S declined last week. The amount of working
rigs fell by 8 to 877, according to data from oilfield-services provider Baker Hughes. That’s the
biggest drop since the week ended Dec. 7.
OPEC Strategy Still a Winner for Members Despite Oil Slump
Given oil’s plummet at the end of last year, OPEC’s strategy to stabilize the market might look a
bust. But where it matters most for the cartel’s members -- petroleum revenues -- it’s still a winner.
Crude prices in London have sunk back to the same range when the group began production cuts
in early 2017, of between $50 and $60 a barrel, as record U.S. oil output and shaky fuel demand
counteract the group’s efforts. That’s below the levels most of its members need to balance
government budgets.
But while the price slide may be an alarming sign for the Organization of Petroleum Exporting
Countries, the strategy of output restraint has continued to deliver what matters most: higher
revenues for their export-reliant economies.
OPEC Is Still Winning
Oil cuts boosted OPEC's revenues in 2017-18

Source: OPEC, Bloomberg data
The nominal value of the group’s crude production, based on the average price of a basket of OPEC
crudes, surged by 33 percent last year, to $826 billion, according to Bloomberg calculations, as
supply cuts from OPEC and its allies bolstered the average oil price. Actual revenues, based on the
volume of crude exported, rather than the total amount produced, would of course be smaller.
Whether that success continues in 2019 is unclear. Prices have had a rocky start to the year on
concerns that a slowing global economy will weaken demand just as a new flood of U.S. shale oil
hits the market.
If the slump persists, the organization could -- as one key producer suggested -- double-down on
the strategy by cutting output even further. Or it might consider whether it’s time to try a different
approach, like returning to the strategy of pumping at full-tilt as in 2015 to 2016.
But staying the course may still be the best option. Even if prices don’t recover from current levels
and OPEC maintains its cuts all year, it’s on track to earn more than during that earlier period.

NewBase Special Coverage
News Agencies News Release 07 January 2019
Winners, losers and unintended consequences in the outlook for
oil product demand… By Kim Tae-Yoon, WEO Energy Analyst
Debates about the future of oil tend to focus on total demand: how long it might continue to grow,
when it might peak, and so on. But digging deeper into the prospects for individual oil products
reveals a rich variety of stories of growth and decline that are also of great significance for the overall
oil outlook.
Global oil consumption has been on an almost unbroken rising trend for decades, but there have
already been divergent trends for individual oil products. Demand for heavy fuel oil, for example,
has been declining since the 1980s, while the pace of demand growth for lighter products – such
as ethane, liquefied petroleum gas (LPG) and naphtha – has been almost triple that of total oil
demand.
In the World Energy Outlook’s New Policies Scenario, heavy fuel oil is set to face another blow
when the International Maritime Organization (IMO)’s regulation on the sulfur content of bunker fuels
comes into effect from 2020. Gasoline demand also peaks in the late 2020s as efficiency
improvements, fuel switching and electrification weigh on oil demand for cars. But there are sectors
where efficiency improvements or electrification are less effective in curbing oil demand, most
notably the petrochemical sector.
As a result, demand for ethane, LPG and naphtha (mainly used as petrochemical feedstocks)
continues to grow much faster than total oil demand in the New Policies Scenario. Robust growth
in these lighter products (also known as the “top of the barrel”) means that their share of total oil
consumption rises from 19% today to 23% in 2040.

In contrast, the share of gasoline and
heavy fuel oil declines from 33% to
28%. Refiners have coped with
divergent trends for different oil
products in the past, but the pace and
extent of the changes envisaged in the
New Policies Scenario still pose a
significant test.
In the Sustainable Development
Scenario, which provides an integrated
strategy to meet Paris climate targets,
achieve energy access, and
significantly improve air quality, the
share of “top of the barrel” products
grows to an even greater extent. Oil
demand in cars drops significantly; consumption for other transport modes – trucks, ships and
aviation – also declines; but use in the petrochemical sector remains robust due to strong demand
growth for chemical products in developing economies.
These changes engender a major shift in the composition of oil product demand. Demand for
gasoline and diesel falls by some 50% and 35% respectively between today and 2040. Demand for
kerosene and fuel oil also falls.
By contrast, demand for ethane, naphtha and LPG grows by around 25%. LPG is also key in this
scenario to tackle the negative health impacts associated with the traditional use of solid biomass
as a cooking fuel in many developing countries. As a result, the share of lighter products rises to
over 30% by 2040 in the Sustainable Development Scenario, which poses an unprecedented
challenge for refiners.
Change in the composition of global oil product Demand

Refiners are used to coping with changing demand patterns. In the past, these efforts were mainly
focused on reducing heavier yields and increasing the output of gasoline and middle distillates
(diesel and kerosene).
The challenge in the Sustainable Development Scenario comes from a different angle: to increase
the yield of lighter products and reduce the output of traditional refined products such as gasoline
and diesel. Growth in the availability of natural gas liquids (NGLs) and lighter crude oil eases some
of the pressure on refiners, at least in the near term. However, production of NGLs and of tight oil
are both projected to fall back post-2025, while demand for lighter products continues to increase.
The mismatch between refinery configurations and product demand in the Sustainable
Development Scenario would increase the incentives for refiners to deepen integration with
petrochemical operations, and thereby boost the direct production of chemical products relative to
transportation fuels. There are various technological pathways to increase chemical product yields
beyond the levels that a refinery can typically produce (less than 10%).
Several Asian refineries have aromatics units attached to a refinery; high-severity fluid catalytic
cracking technologies are being explored; while companies in China are building integrated
petrochemical and refining facilities that aim to have chemical yields of around 40%. There are even
more ambitious schemes being pursued in the Middle East to bypass refining operations and
produce chemicals directly from crude oil.
Implications for the refining industry
The changes in product demand could also have profound implications for the business model of
the refining industry. Today, refiners typically earn most of their profit from selling road transport
fuels such as gasoline and diesel. Prices for petrochemical feedstocks – the main sources of
demand growth – often trend lower than crude oil prices. The significant reduction in road transport
fuel demand may therefore challenge this traditional pattern.

In theory, foregone profits in one area would be compensated by higher prices for products in high
demand such as naphtha and LPG. While it is conceivable for the prices of these products to
increase to some degree, it is hard to envisage a rise that fully compensates for the reduction in
road transport fuels sales. The current interest in petrochemical integration reflects a desire to hedge
against this risk by seeking out new business lines and revenue streams.
Implications for the energy transition
The IMO sulfur regulation is expected to increase demand for diesel and reduce that for high-sulfur
fuel oil (HSFO) around 2020. This raises the prospect of a spike in diesel prices and a drop in HSFO
prices, which could have broader economic ramifications beyond oil product markets. The regulation
may provide an illustration of how changes in product demand can send ripples through the refining
industry and then through the wider energy system.
Our projections highlight other possible mismatches between products demanded and refinery
configurations, causing spikes or slumps in the price of individual oil products. While policy makers
need to try to minimise the potential impacts of price spikes on energy consumers, they would also
need to be attentive to the unintended influences of price slumps.
For example, if policy action were concentrated narrowly on the passenger car segment while other
sectors – such as trucks, aviation, shipping and petrochemicals – were left relatively untouched, it
would be difficult to avoid a glut of gasoline on the market once demand started to fall back. Efforts
to curb oil use in passenger cars would therefore face much stronger headwinds because cheap
gasoline would make efficiency improvements and electrification more difficult and expensive.
Avoiding such rebound effects would require removing fossil fuel subsidies or putting in place an
offsetting tax or duty that maintains end-user prices at higher levels. Anticipating and mitigating
these feedbacks from the supply side needs to be a central element of the discussion about orderly
energy transitions.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
The Editor :”Khaled Al Awadi” Your partner in Energy Services
NewBase energy news is produced daily (Sunday to Thursday) and
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Energy
Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
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.
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase January 2019 K. Al Awadi

New base energy news 07 january 2019 issue no 1222 by khaled al awadi

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