New base 18 january 2018 energy news issue 1129 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 18 January 2018 - Issue No. 1129 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: Adnoc to boost carbon capture in oilfields by six-fold over
the next 10 years
The National - Dania Saadi
Abu Dhabi National Oil Company plans to expand its carbon capture programme to cater to a six-
fold increase in the use of CO2 in maturing oilfields, a measure that will free up gas injected into
the fields for other industries and boost oil recovery rates.
The state-owned energy company plans to increase its utilisation of the carbon capture, use and
storage (CCUS) technology in its fields by capturing CO2 from its own gas processing plants and
injecting it into different onshore oilfields, the company said in a statement on Wednesday.
Adnoc will start to increase utilisation of CO2 in 2021 to reach 250 million standard cubic feet per
day by 2027. Current supplies of the green house gas are collected from Emirate Steel Industries
and injected into the Rumaitha and Bab oilfields to boost oil recovery. Adnoc plans to increase the
oil recovery rate to 70 per cent from its reservoirs, which is twice the global average. Including
waterflood, Adnoc achieves up to 50 per cent recovery rate from its fields. Use of enhanced oil
recovery techniques, including CO2 and CCUS, can boost recovery rate to up to 70 per cent.
“As we push forward plans to create value by maximising oil recovery over the life time of our
fields, we will increasingly utilise a range of Enhanced Oil Recovery technologies, of which carbon
Al Reyadah, the CCUS facility in Mussaffah owned by Adnoc, currently has
the capacity to capture up to 800,000 metric tonnes of CO2 a year.

capture, use and storage is not only good for the environment but also makes sound business
sense,” said Abdulmunim Al Kindy, director of Adnoc’s upstream directorate.
The International Energy Agency has urged the international community to invest more in carbon
capture storage (CCS) technology as a means of tackling climate change.
“The under-investment in CCS is deeply concerning,” said the IEA's executive director Fatih Birol
at a summit in November. “We know that we face an unprecedented challenge in meeting climate
goals. Without CCS, this challenge will be infinitely greater. We also know that this is essentially a
policy question.”
The UAE and Saudi Arabia are leading regional efforts to capture CO2 and inject it into oilfields to
free up gas pumped into the fields for use in power and water generation, petrochemical
production and other industries. Currently there are 17 carbon capture and storage faciltiies
globally and two of them are in the Middle East, in the UAE and Saudi Arabia, according to the
Global CCS Institute.
“Replacing rich gas with CO2 injection into Adnoc’s maturing fields will allow the more productive
use of valuable clean-burning natural gas, whether for power generation, desalination or as
petrochemicals’ feedstock,” said Mr Al Kindy. “This is a prime example of how clean technology
can be integrated with traditional energy to optimise resources and reduce the environmental
footprint.”
Al Reyadah, the CCUS facility in Mussaffah owned by Adnoc, currently has the capacity to
capture up to 800,000 metric tonnes of CO2 and plans to boost that capacity to 5 million metric
tonnes per year by 2027.
Saudi Arabia has an 800,000 tonne-capacity CCS plant at Uthmaniya in the eastern province that
was set up in 2013. The facility compresses and dehydrates CO2 from the Hawiyah natural gas
liquids recovery facility, which is then transported via pipeline to be injected into the Ghawar field,
the world's biggest oil field.

Share of renewable energy in ME to more than triple by 2035
Oman Observer
The region is expected to require a total of 483 gigawatts (GW) of power generation capacity by
2035, an addition of 277 GW from 2016, according to a new energy outlook report by Siemens.
Within this, the share of renewables in the power mix is expected to more than triple from 5.6 per
cent (16.7 GW) in 2016 to 20.6 per cent (100 GW) in 2035.
This increase highlights the need for reliable and efficient energy storage solutions, as well as
mixed power generation sources to overcome the intermittent nature of renewables and achieve
grid stability.
Based on the Siemens’ ‘Middle East Power: Outlook 2035’ report, despite the growing share of
renewables natural gas is expected remain the No 1 source for power generation in the region,
representing 60 per cent of installed capacity through 2035.
With economic diversification and population growth accelerating, the growth in power demand in
the region 0151 approximately 3.3 per cent per year — will be realized predominantly through
increasingly efficient natural gas-fired power plants. Capacity additions will primarily be highly
efficient Combined Cycle Power Plants (CCPPs), which are expected to dominate the power plant
landscape by 2030.
The report also assessed upcoming challenges to the diversification of energy sources as well as
enablers such as digitalization and decentralized energy systems.
“A reliable, efficient, flexible and affordable power supply is the backbone of economic and social
development in the Middle East. While the energy mix will see significant diversification over the
next 20 years, natural gas will remain the prime energy source for power generation in 2035,” said
Dietmar Siersdorfer, CEO, Siemens Middle East and the UAE. “We expect the majority of new

power generation capacity to be via highly efficient combined-cycle power plants, but renewables
will also gain a substantially increased share of the energy mix.”
There is also greater potential if CCPPs are considered in place of planned steam power plants.
Aside from new capacity additions, an additional 45 GW could also be realized through
efficiencies brought about by upgrading facilities older than 30 years.
Solar power is expected to account for additions of around 61GW by 2035, and the report
highlights significant potential for wind power generation in Saudi Arabia and Egypt, but notes that
this potential is not entirely reflected in the moderate capacity additions expected.
Furthermore, cost-competitive storage solutions continue to remain an obstacle for widespread
adoption of renewable energy technologies. Aside from PV panels, Siemens is a one-stop supplier
of all key components of solar power plants.
Masdar, a partner to Siemens and a pioneer in the clean energy space in the region, contributed
to the report. “The convergence of technologies is promising a paradigm shift in the way in which
we produce and consume energy, and there is no question that the Middle East will be at the
heart of the transformation taking place,” said Mohamed Jameel al Ramahi, Chief Executive
Officer of Masdar.
“This thought-provoking report will broaden the understanding of any audience confronting the
changing dynamics of the Middle East’s power sector.”
A key enabler identified by the report is digitalization. A gas turbine can produce 30 gigabytes of
data per day, and the report points out that using digitalization tools to harness this data and use it
intelligently will be an important factor in increasing the efficiency and flexibility of energy supply,
while decreasing production costs.

India to auction 55 oil and gas exploration blocks
Source: Reuters
India will begin the auction of 55 oil and gas exploration blocks from Thursday under new rules,
the country’s first licensing round after eight years, as it seeks to unlock its vast hydrocarbon
resources, the upstream regulator said.
The world’s third biggest oil importer last year eased rules and allowed companies to carve out
areas where they want to drill to attract greater interest and quickly monetise as much as 220
billion barrels of oil and gas resources.
The identified blocks, spread over
a 59,000 sq km area, will now go
under the hammer with some
advantages given to companies
that first identified the area.
'We are now putting up the blocks
for bidding to ensure transparency
and greater participation,' Atanu
Chakraborty, head of India’s
Directorate General of
Hydrocarbons, told Reuters.
India imports nearly three-quarters
of its energy requirements but
Prime Minister Narendra Modi has
set a target of cutting the country’s
fuel import dependency to two-
thirds by 2022 and to half by 2030.
In previous licensing rounds, India
had muted response from global
oil firms but Chakraborty is hopeful
of getting a good response as oil
prices are moving up. 'With oil
prices now looking up, we
anticipate good interest and more
people would come in for
exploration,' he said.
The last date to submit bids is on
April 3 and the contracts are
expected to be signed by the end
of July, he said. 'This is the
biggest offering (of blocks) in the
last decade and we are offering a high-quality area, as the companies themselves have chosen it,'
he said. About 65 percent of the 55 blocks are on land and mostly in the northeastern state of
Assam and western states of Gujarat and Rajasthan.
India is estimated to hold 42 billion tonnes or 315 billion barrels of oil and gas resources, he said.
'Of this, 220 billion barrels are yet to be discovered,' he said.

U.S: Natural gas prices, production, and exports increased
from 2016 to 2017Source: U.S. Energy Information Administration,
In 2017, natural gas spot prices at the national benchmark Henry Hub in Louisiana averaged
$3.01 per million British thermal units (MMBtu), about 50 cents per MMBtu higher than in 2016.
The higher prices in 2017 contributed to less natural gas consumption for power generation.
Increased domestic production was offset by increased exports of natural gas by pipeline and
liquefied natural gas (LNG) cargoes.
Overall, natural gas prices at key regional trading hubs were less volatile in 2017 than in previous
years, as pipelines that came online throughout the year eased some infrastructure constraints
that affect regional prices.
In the Northeast, which tends to have large price spikes during periods of cold weather, new
pipeline capacity, along with warmer winter weather, helped to moderate price volatility.
However, record cold temperatures at the end of December in the eastern United States led
to record high demand for natural gas and significant price spikes at many trading locations.
Additional takeaway capacity in the Appalachian region, the region with the largest U.S. natural
gas production growth in 2017, continued to narrow price differences between Henry Hub and
nearby trading hubs such as Dominion South in western Pennsylvania, Transco Zone 6 NY in
New York City, and Algonquin Citygate near Boston, Massachusetts.
Until the last few days of 2017, relatively warm winter weather limited natural gas consumption
growth in the residential and commercial sectors compared with 2016 levels. However, higher
natural gas prices contributed to a 6% year-on-year decline in natural gas consumption for power

generation, based on data through October and projections for November and December. This
decline was despite a large increase in natural gas-fired capacity additions in 2017, as coal
became more competitive with natural gas.
Mild winter temperatures in early 2017 also limited natural gas storage withdrawals, with the first-
ever net injectionrecorded in the month of February. As a result, natural gas storage
inventories ended the injection season lower than last year, but higher than the previous five-year
average.
EIA expects the United States to become a net exporter of natural gas on an annual basis in 2017
for the first time since 1957. The United States is exporting more natural gas to Mexico and more
LNG to at least 20 countries while importing less natural gas by pipeline from Canada.
Although EIA’s monthly natural gas data for December 2017 will not be available until the end of
February 2018, EIA expects the United States to have exported 0.4 billion cubic feet per day
(Bcf/d) more natural gas than it imported in 2017.
U.S. net pipeline imports from Canada continued to decline in 2017, in part because of the
commissioning of the first phase of the Rover pipeline, which transports natural gas from the
Northeast’s Appalachian supply basin to the Midwest and other markets, reducing Canadian net
exports into the Midwest.

U.S. LNG exports averaged 1.9 Bcf/d in 2017, 1.4 Bcf/d higher than in 2016, as liquefaction
capacity continued to expand. Currently, the Sabine Pass LNG terminal in Louisiana is operating
at near-full capacity with additional liquefaction capacity to be added in the near future.
The Cove Point LNG terminal in Maryland plans to start commercial operations in the next few
months, and four additional LNG projects are under construction in Georgia, Texas, and
Louisiana. By the end of 2019, assuming all liquefaction facilities currently under development are
completed, EIA expects U.S. liquefaction capacity to reach 9.6 Bcf/d, the third largest in the world
behind Qatar and Australia.
Future U.S. pipeline exports to Mexico are supported by a near doubling of U.S. export pipeline
capacity to Mexicoby 2019. However, further growth in natural gas pipeline exports to Mexico will
be contingent on the timely completion of Mexico's connecting pipelines, which so far have
experienced construction delays.
U.S. marketed natural gas production increased by 1% (1 Bcf/d) in 2017, according to EIA's
preliminary estimates for the year. Regionally, natural gas production growth was concentrated in
Appalachia—primarily in the Marcellus and Utica shales. Other regions have also increased
production, including the Anadarko region in Texas and Oklahoma and the Bakken region in North
Dakota.

NewBase January 18 - 2018 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil stable on threats of attacks in Nigeria, falling U.S. crude stocks
Reuters + NewBase + Bloomberg
Oil prices were stable on Thursday, supported by tighter inventories of crude as well as rebel
threats of an attack on Nigeria’s petroleum industry, but the market was weighed down by a
reported rise in U.S. fuel stocks.
Brent crude futures were at $69.34 at 0753 GMT, down 4 cents from their last close. On Monday,
they hit their highest since December 2014 at $70.37 a barrel. U.S. West Texas Intermediate
(WTI) crude futures were at $64.03 a barrel, up 6 cents from their last settlement. WTI marked it
highest since December 2014 at $64.89 on Tuesday.
Traders said that oil markets were generally well supported by supply cuts led by the Organization
of the Petroleum Exporting Countries (OPEC) and Russia, who started to withhold production in
January last year and are expected to continue their restraint through 2018.
Oil price special
coverage

Despite this, analysts said the recent oil price rally, which has lifted crude by around 14 percent
since early December, may be about to run out of steam. Data from the American Petroleum
Institute (API) on Wednesday showed a well supplied fuel product market, which could mean
lower crude demand going forward.
U.S. refinery crude runs fell by 420,000 barrels per day (bpd) and refined product stocks rose,
implying a well supplied market. Gasoline stocks rose by 1.8 million barrels while distillate fuels
stockpiles, which include diesel and heating oil, climbed by 609,000 barrels, the API data showed.
Refined product supplies in Asia are also healthy, largely thanks to a sharp rise in exports from
China.
“The upside is now limited for oil prices ... U.S. oil producers will ramp up production in the coming
months ... U.S. shale oil output will increase by a good 111,000 barrels per day (bpd) next month
to 10 million bpd, and ... will rise to about 11 million bpd by the end of next year. This would put
the U.S. on par with Saudi Arabia and Russia’s output,” said Fawad Razaqzada, market analyst at
future brokerage Forex.com.
Coface, a French trade credit insurance company, said it “forecasts oil prices will consolidate
some gains to average $65 (per barrel) in 2018.” The firm said the reasons for this expected
slowdown were an expected rise in U.S. oil output as well as a slowdown in demand growth.
Despite this, traders said prices were unlikely to fall far due to risks to supply disruptions. In
Nigeria, the militant group Niger Delta Avengers threatened to launch attacks on the country’s oil
sector in the next few days.
Markets were also supported by a drop in available crude inventories.
U.S. crude inventories fell by 5.1 million barrels in the week ended Jan. 12 to 411.5 million,
according to the API. Official U.S. oil inventory and production data is due on Thursday from the
Energy Information Administration (EIA).

OPEC-Russia Oil Deal Faces a New Danger: Too Much Winning
When OPEC and Russia meet this weekend to review their strategy for clearing a global oil glut,
they’ll face an unusual problem: it could be working just a bit too well.
As their output cuts, coupled with robust global demand, tighten the market, crude prices have
soared to a three-year high near $70 a barrel. That’s prompted warnings -- from Iran’s oil
minister to Goldman Sachs Group Inc. -- of a fresh surge in U.S. production, wrecking all of
OPEC’s hard work.
“The big concern is prices -- are they worried about prices going too high too quickly?” said Mike
Wittner, head of oil-market research at Societe Generale SA in New York. “There are many
reasons they’d be concerned, but top of the list is: how will U.S. production respond?”
With plenty of surplus oil still around, ministers from the United Arab Emirates, Iraq
and Kuwait insist there’s no need to change strategy and the cartel will stick with its plan to
restrain production for the rest of the year. Nonetheless, the price jump means that delegates
gathering in the Omani capital of Muscat face increased urgency to decide how to phase out the
curbs.
“Getting too far above $70” can both stimulate new supply and affect the economy, Jeff Currie,
head of commodities research at Goldman Sachs, said in a television interview. “OPEC members
do not want to see that.”
Fierce competitors for decades, the Organization of Petroleum Exporting Countries and Russia
joined forces in late 2016 against the threat posed by a boom in U.S. shale oil, which had flooded
markets and sent prices crashing. To offset the American bonanza, OPEC and Russia assembled
a coalition of 24 nations that would cut their own production.

For much of 2017, they struggled, as global inventories remained bloated and prices depressed.
But the strategy gained traction in the second half of the year as stronger demand and supply
threats from the Persian Gulf to the North Sea helped deplete brimming storage tanks.
Prices responded, with Brent crude futures climbing to $70.05 on Jan. 11, the highest since
December 2014. While that gives oil-producing economies much-needed relief, it also presents
them with troubling consequences. Energized by new investment, U.S. production could top 11
million barrels a day next year, surpassing both Saudi and Russian output, according to U.S.
government forecasts. That compares with an estimate of 9.3 million a day for 2017.
“There is an unintended consequence from this higher price,” said Ed Morse, head of commodities
research at Citigroup Inc. “OPEC are fearful of not only the shale response, but of deep water and
of oil sands from Canada.”
That said, burgeoning crude demand will help to mop up some of the additional output. Global
consumption will expand by about 1.5 million barrels a day this year, OPEC Secretary-General
Mohammad Barkindo said earlier this month.
The producers will formally review their accord in June, and may start to wind it down in the
second half of the year, Citi’s Morse and SocGen’s Wittner said. Saudi Arabia and Russia, the
biggest producers in the pact, have repeatedly stressed that when the time comes to end the deal
it will be done gradually.
In the meantime, the pressure to change strategy is likely to ease in coming weeks as oil prices
retreat, the two banks predict. Crude futures will slip in tandem with a lull in seasonal demand as
the need for winter fuels abates, and as hedge funds take profits from the recent rally.
“For now, with the price strength looking very temporary, I think OPEC will say we’re on our way to
getting the market rebalanced, and keep going,” Morse said. But that resolve may not last all year.
“There could be an agreement on ramping production back up over the summer.”

Oil at $70 Proves Too Hot to Handle for Some European Refineries
Oil’s surge to $70 a barrel has left plants that process crude in Europe struggling, as their margins
plunge and demand weakens for some of what they make.
The slump is most evident in the market for fuel oil, which is used in shipping and by power
producers. Diesel also isn’t helping as high inflows of the fuel from the Middle East are capping
those margins. The slump in profitability could start to curb refinery runs, according to KBC
Advanced Technologies.
Refining margins have fallen to the lowest in 3 years, according to Barclays, which says fuel oil
demand is being hit as crude rises. So-called hydroskimming refineries are particularly vulnerable
to the slump in fuel oil because they are less able than complex refiners to convert fuel oil into
diesel or gasoline.
“Fuel oil cracks are paltry, which is impacting hydroskimming margins, with Urals margins in
particular falling,” said Ehsan Ul-Haq, London-based director of crude oil and refined products at
researcher Resource Economist Ltd. Russian Urals has a higher fuel oil yield than other crude
grades, making it more sensitive to weakness in the fuel oil market.
Mediterranean hydroskimming refineries running Urals were losing $2.04 per barrel on Jan. 11,
the least profitable rate since May 2016, according to data from Oil Analytics Ltd. High sulfur fuel
oil’s discount to Brent, another indicator of refining profitability, has also slumped since late
August.
Barclays’ refining margin indicator in NW Europe tested August 2016 lows at $1.14 a barrel last
week, it said in a note on Tuesday.
“Oil demand usually slackens in the first quarter and into the second quarter, so sooner or later
refinery intakes will have to slacken and the usual signal for that is lower margins,” according to

Stephen George, chief economist at KBC Advanced Technologies. Simple refineries, those plants
with lower capacity to convert crude into high-value products, will suffer the most, he said.
High imports of fuels like diesel from the Middle East are also capping profits for European
refiners. Shipments of fuels from that region to Europe are forecast to rise in January to the
highest in at least a year, according to tanker tracking and fixture data compiled by Bloomberg.
“Given refiners have been trying to maximize runs to take advantage of the especially good
margins in the last couple of years -- now with lower margins, we could see slightly lower run
levels all around,” says Salih Yilmaz, an analyst at Bloomberg Intelligence.

NewBase Special Coverage
News Agencies News Release January 18-2017
Wholesale power prices in 2017 were stable in the east, but
increased in Texas, California.. U.S. EIA, based on data from S&P Global Market Intelligence
Wholesale electricity prices at major trading hubs in the eastern United States during 2017 were
relatively unchanged from 2016, while average monthly wholesale prices in California and Texas
increased by 18% and 27%, respectively, in 2017. Less volatility in natural gas fuel prices through
the year contributed to stable wholesale electricity prices in most areas of the United States,
although late summer heat waves resulted in short-term price spikes in some western electricity
markets.
Average peak day-ahead wholesale electricity prices in regions controlled by the PJM
Independent System Operator (ISO), which covers many parts of the Mid-Atlantic and Midwestern
states, averaged about $34 per megawatthour (MWh) during 2017, 1% lower than in 2016.
Although prices in ISO New England spiked to $75/MWh in December, the average annual
wholesale price of $38/MWh in 2017 was just 7% higher than the 2016 average.
Hot summer temperatures in California led to periods of high electricity demand, which neared
record hourly levels in the late summer. Wholesale prices during peak hours averaged $55/MWh
in August, 42% higher than in the same month in 2016. On September 1, day-ahead electricity
market prices in the California ISO were higher than $200/MWh for four hours and reached
$770/MWh in one hour.
Electricity markets throughout the United States benefited from relatively low natural gas fuel
costs. The monthly average price of natural gas delivered to U.S. electric generators peaked at

$4.14 per million British thermal units (MMBtu) in January 2017, but during the second half of the
year the average price stayed within a narrow range of $3.10/MMBtu to $3.30/MMBtu.
Source: U.S. Energy Information Administration, Electric Power Monthly and Short-Term Energy Outlook
The continued low cost of natural gas also permitted it to remain the dominant source of U.S.
power generation for the second year in a row. EIA estimates that natural gas-fired power plants
supplied an average of 32% of total U.S. electricity in 2017, compared with 30% supplied by coal-
fired power plants. The natural gas share of generation was down slightly from an average of 34%
in 2016, as generation from renewable energy continued to grow.
Source: U.S. Energy Information Administration, Electric Power Monthly and Short-Term Energy Outlook

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
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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 2018 K. Al Awadi

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New base 18 january 2018 energy news issue 1129 by khaled al awadi