New base special 26 february 2014

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NewBase 26 February 2014 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Adco developing sixth oil field at Al Dabb'iya
By Stanley Carvalho, Staff Reporter – Gulf News
The Abu Dhabi Co for Onshore Oil Operations (Adco) is developing its sixth oil field at Al Dabb'iya
to raise production by 200,000 barrels per day (bpd) by mid-2006. The company, which is
producing oil from five fields, is also initiating new smart wells technology to optimise reservoir
management.
"The sixth field of Adco, the Al Dabbi'ya field in the onshore area, is being developed. Production
will start in the middle of 2006," said Andre Van Strijp, general manager, Adco. "The field is
northeast of the Bab field. It is an environmentally sensitive area, but we are still developing it with
minimum environmental impact," he told Gulf News yesterday.
Adco produces a little more than one million bpd from its five onshore oil fields. Asked if Adco will
develop more fields, Van Strijp said: "It depends on the needs. We are flexible and we are building
capacity to meet demand. We are always looking at developing new fields but expansion depends
on demand."
Adco is working on introducing the smart wells concept for enhanced oil recovery, with the
technology already proven. "In northeast Bab, we will use the smart wells or intelligent technology
that will help in optimising production and help optimise reservoir management. It is very cost
effective and does not entail much
investment."
As one of Adnoc's subsidiaries, Adco has
grown greatly in the past 40 years to
become one of the top oil-producing
companies in the UAE. From about 60,000
bpd of crude oil in the 1960s to a little
more than one million bpd, Adco continues
to grow.
Adco is owned 60 per cent by Adnoc and
the remaining 40 per cent is owned
equally by Shell, Exxon-Mobil, BP and
Total, each with a 9.5 per cent equity, and
Partex with a 2 per cent stake.
As one of Adnoc's subsidiaries, Adco has
grown greatly in the past 40 years to become one of the top oil-producing companies in the UAE.
From about 60,000 bpd of crude oil in the 1960s to a little more than one million bpd, Adco
continues to grow .

NewBase Commentary & research :-
The North East Bab (NEB) Asset is located 31 km from the UAE capital, Abu Dhabi. The asset comprises three
producing fields, Al Dabb’iya, Rumaitha, and Shanayel and one undeveloped culmination, Jumaylah. The Al
Dabb’iya field lies on a coastal/shallow and deep marine area, while the Rumaitha/Shanayel fields lie onshore. The
developed fields cover an area greater than 1,400 km2.
NEB produces approximately 8% of ADCO’s production. The main hydrocarbon reservoirs in the NEB structures are
Thamama Zones ‘A’, 'B', 'C’ , ‘F’ , ‘G’ and Habshan. However, there are significant number of zonesunits that are
under early production schemes and will be developed in the coming future.
NEB is located in one of the most environmentally sensitive areas which include desert, sea, mangroves, salt marshes,
coral reefs and Sabkha, all supporting diverse wildlife species. The marine environment is both highly sensitive and of
great ecological importance. In addition, the area is also of archaeological significance. New technologies and
management systems were implemented to minimize the impact of ADCO's operations on the environment.
(ADCO) is currently evaluating the offers for the third phase of the North East Bab (NEB-3) project onshore Abu
Dhabi. As the other projects Upper Zakum, Umm Al-Lulu or Al-Nasr, NEB-3 is part of the giant upstream projects in
Abu Dhabi to help the UAE to meet their targeted quotas of production in 2018.
In line with the other producing countries sitting at the OPEC, the goal is for each member to increase its production
of crude oil so that the OPEC countries together can sustain their 40% market share globally. In that perspective, Abu
Dhabi is expected to reach 3.5 million barrels per day (b/d) in 2018. Considering that the crude oil production increase
must begin with compensating the natural decline of the maturing fields, such a goal represents a major effort for the
producing countries.
All the companies of the Abu Dhabi National Oil Company (ADNOC) are involved in this program where ADCO is
expected to contribute in ramping up its current production of 1.4 million b/d to 1.8 million b/d by 2018. Within
ADCO assets portfolio, the third phase of North East Bab is expected to bring 110,000 b/d additional output. Located
less than 50 kilometers southwest of Abu Dhabi City, NEB lies along the shore line with onshore and offshore oil and
gas fields.
Onshore, NEB includes the Rumaitha and Shanayel oil fields. Offshore, NEB relies on the Al-Dabbiya oil field.
In between these fields, the coast line area is
considered by Abu Dhabi Authorities are
environmental sensitive,. ADCO to phase up
Onshore – Offshore NEB-3 project
Since the development of the onshore part and
offshore portion of NEB-3 had to be split anyway,
ADCO decided to phase up the project and the
organize the call for tender separately for the onshore
and offshore packages of the NEB-3 project.
For the development of Al-Dabbiya as part of NEB-
3 Offshore project, ADCO is still evaluating offers
for the front end engineering and design (FEED)
work, while Technip completed the FEED for the
Rumaitah and Shanayel onshore fields development
project. In the meantime ADCO awarded the project management consultancy (PMC) contract to Mott MacDonald in
2012. From the 13 companies qualified by ADCO for Onshore NEB-3 engineering, procurement and construction
(EPC) contract, 10 submitted a technical and commercial offer.
ADCO is currently evaluating these offers in order to make a decision at the end of 2013 or early 2014. If ADCO is
still willing to reach its production goal by 2018, it will have to move the NEB-3 project into the execution phase
without any delay.

Mediterranean Oil & Gas announces Y/E 2013 Reserves and Resources update
Source: Mediterranean Oil & Gas
Mediterranean Oil & Gas has announced an update of the Reserves and Resources of the Company as at 31
December 2013. MOG's technical team has reviewed the entire portfolio and worked closely with our
Corporate Reserves auditors, ERC Equipoise ('ERCE'), to enable ERCE to
certify the majority of its fields and Prospects.
MOG Total Reserves:
Total Proved and Probable ('2P') Reserves are 5.3 Bcf (0.96 MMboe) of gas and 2,376 bbls of associated
condensate. 2P Reserves were significantly reduced compared to year-end 2012 following the
announcement of the movement of Ombrina Mare Reserves to Contingent Resources in October 2013.
Considering gas Reserves only, after adjustment for 2013 production, 2P Reserves dropped by 1.3 Bcf,
which is a downward adjustment of 19% compared to the equivalent 2P Reserves at year-end 2012. The
bulk of this revision is in the Onshore Italy Foredeep assets of San Basile and Torrente Celone where
previously Reserves were re-classified as Contingent Resources pending approval of work programmes
required to commercialise the resources.
Despite the production challenges at the Guendalina Field in 2013, Guendalina 2P Reserves net to MOG
have only decreased by 7%, to 3.7 Bcf, compared to the production adjusted booking at year-end 2012.
MOG Total Contingent Resources:
Total most likely Contingent Resources ('2C') are 32.4 Bcf (5.81 MMboe) of gas and 25.99 MMbbls of oil.
Gas 2C Contingent Resources have increased by 10.1 Bcf compared to year-end 2012, driven by the
movement of booked Reserves to Contingent Resources at Ombrina Mare, San Basile and Torrente Celone.
As noted above, these resources will move back to Reserves when there is commercial progress on the
assets.
Oil 2C Contingent Resources have increased by 9.10 MMbbls compared to year-end 2012, driven by the
movement of previously booked Reserves to Contingent Resources at Ombrina Mare. ERCE's certification
of Ombrina Mare also resulted in a significant movement of resources from 2C to the high estimate '3C'
category. The oil 3C Contingent Resources have increased by 34.80 MMbls to 65.81 MMbbls.
MOG Total Prospective Resources:
Total most likely Prospective Resources ('2E') are 144.3 Bcf (25.34 MMboe) of gas and 424.09 MMbbls of
oil.
Gas 2E Prospective Resources have increased by 30.6 Bcf compared to year-end 2012, driven by the
addition of associated gas for the Monte Grosso Prospect in the Southern Apennines. ERCE having certified
26.7 Bcf (19%) of those resources, will continue to work with the Company to review the remaining assets
by year end 2014.
Oil 2E Prospective Resources have decreased by 46.37 MMbbls compared to year-end 2012 driven by the
downward adjustment of the certified Resources for the Monte Grosso Prospect in the Southern Apennines.
ERCE has certified low estimate ("1E") of 9.84 MMbbls, 2E of 29.87 MMbbls and high estimate ("3E") of
85.33 MMbbls, net to MOG for the Monte Grosso Prospect. In addition, the Company estimates that Monte

Grosso has associated gas resources of 1E of 10.0 Bcf, 2E of 20.7 Bcf and 3E of 56.8 Bcf. The Monte
Grosso Prospect has a mean unrisked size of 48.8 MMboe net to the Company (213 MMboe gross
resources) and continues to be a substantial prospect within MOG's portfolio. ERCE has certified 96.7
MMbbls (23%) of those resources and will work with the Company to review the remaining assets as they
mature.
The tables below summarise the comparison of oil and gas Reserves and Resources net to MOG for year-
end 2012 and year-end 2013.
Dr. Bill Higgs, Chief Executive of Mediterranean Oil and Gas, commented:
'In 2013 we set ourselves the goal to revisit the key elements of our portfolio and standardise the
certification of our assets. We have worked very closely with ERCE on this project and we believe that the
result provides additional confidence in the value of our portfolio.
In 2014 we look forward to drilling two exploration wells, one offshore Malta and one onshore Italy, which
will enable us to evaluate key Prospective Resources. In addition we are acquiring 1500km of 2D seismic
offshore Malta in Area 3, which could add additional Prospective Resources by the end of 2014.'

PetroSaudi eyes JV deal with Ghanaian refinery
By Reuters
Ghana's sole refinery, the Tema Oil Refinery (TOR), is close to signing a joint venture agreement with
PetroSaudi International and a deal is expected soon, Ghanaian President John Mahama said on Tuesday.
The 45,000 barrels-per-day plant has been
hobbled by repeated shutdowns in the last
four years, often due to a lack of funds to
procure crude for processing.
"A joint venture agreement between TOR
and PetroSaudi is being finalised to revamp
the operations of our refinery. This will
reduce the huge amount of foreign
exchange spent on importing finished
products," Mahama said in his state of the
union address to parliament without giving
details. Ghana is one of Africa's newest crude exporters after starting production from its offshore Jubilee
field in late 2010. But authorities say the country's refinery needs an upgrade to be able to run the
domestically produced oil.
Oil production has become a major source of government revenue and foreign exchange and when it came
on stream it led to a spike in GDP growth in 2011, making Ghana one of the world's fastest growing
economies. Current output stands at around 100,000 barrels per day and lags national targets.
About Ghana oil :- ( by NewBase research )
The Ghanaian government, indicated that the country could expand its reserves up to 5 billion barrels
(790,000,000 m3
) of oil in reserves within a
few years.
The expected annual tremendous inflow of
capital from crude oil and natural gas
production into the Ghana economy began
from the first quarter of 2011 when Ghana
started producing crude oil and natural gas in
commercial quantities in 2011. At the end of
2012, declining productivity at one of the
country’s largest oil projects, the Jubilee oil
field, led to a decline in revenues for the
government, who had budgeted for oil revenue
of more than $650 million. The corresponding
shortfall was more than $410 million. The oil
firm blamed the decline on “sand
contamination of the flow lines that carry the

oil from the underwater wells” into the storage facility on the surface.
In the first and second financial quarters of 2013, South Ghana produced 115,000-200,000 barrels of crude
oil per day and 140 million-200 million cubic feet of natural gas per day. The 100% Iranian state-owned oil
companies National Iranian Oil
Company and Iranian Offshore
Oil Company, and Singapore
Petroleum Company with Vetro
Energy and PetroSeraya of
Singapore have declared interests
to provide assistance in
construction of offshore platforms
and drilling rigs for Ghana's state-
owned oil company, Ghana
National Petroleum Company on
rapidly developing South Ghana's
oil and gas infrastructure and
industry as South Ghana aims to
further increase output of oil to 2
million barrels per day and gas to
1.2 billion cubic feet per day with
an expected annual generating revenue of GH₵140.7 billion (US$65 billion) in 2014.
South Ghana is believed to have up to 5 billion barrels (790,000,000 m3
) to 7 billion barrels (1.1×109
m3
) of
petroleum in reserves which is the sixth largest in Africa and the 25th largest proven reserves in the world
and South Ghana has up to 4 trillion cubic feet of natural gas in reserves. The Parliament of Ghana has
drawn plans to nationalize Ghana's entire petroleum and natural gas reserves.
• After discovering the Jubilee oil field in 2007, Ghana's energy sector has expanded considerably. The field
came online in 2010, and production in Ghana has since jumped from 7,000 barrels per day (bbl/d) in 2009
to 78,000 bbl/d in 2011, and 80,000 bbl/d in 2012. Tullow, the field's operator, experienced technical
problems at the field that caused production to fall well below output goals in 2012.
• Proved crude oil reserves are 660 million barrels, as of January 1, 2013. However, given recent discoveries
and further oil exploration, proved reserves are expected to rise.
• Ghana has about 800 billion cubic feet (Bcf) of proved natural gas reserves, although the country does not
currently produce dry natural gas. Ghana plans to build a natural gas pipeline to pipe associated gas at oil
fields, which is currently flared and reinjected. Ghana imported 29 Bcf of natural gas in 2011, mostly from
Nigeria. Some of those imports came via the West African Gas Pipeline (WAGP), which runs east to west
from Nigeria to Ghana.
• The Ghanaian government passed the Petroleum Revenue Act in 2011, which outlines clear mechanisms for
collecting and distributing petroleum revenue and mandates a certain percentage to help fund the national
budget. Ghana's state-owned company, the Ghana national Petroleum Company (GNPC), was established in
1983 to oversee exploration, development, production, and disposal of petroleum. GNPC owns a small
minority share in the Jubilee oil field.
• Most Ghanaians rely on biomass sources, particularly wood fuels and charcoal, for household needs.
Government statistics place consumption of biomass fuels at slightly more than 60 percent of total energy
consumption in Ghana. However, as part of the Ghana Shared Growth and Development Agenda, Ghana
would like to reduce reliance on wood fuels and charcoal by expanding access to the national electric grid
and developing oil and gas resources.
• Ghana relies heavily on hydroelectricity, which accounts for 85 percent of electricity generation. But past
droughts have disrupted supplies, and the country hopes to increase electricity generation from natural gas.
The former Ghana president John Atta Mills turns the
valve to flag off first oil production at the FPSO Kwame
Nkrumah oil rig. Pius Utomi Ekpei / AFP

Sonangol 'to exit Iraq'
REUTERS + Steve Marshall ,
Angolan state oil company Sonangol reportedly has decided to exit Iraq due to security concerns, with
Italy’s Eni also threatening to do the same unless key contracts are signed in the next few weeks.
Sonangol won in 2009 the right to operate the Qayara and Najmah oilfields in the Nineveh province in
north-west Iraq where Sunni Islamist insurgents remain active.
Board member in charge of international investments, Anabela Fonseca, told a news conference on Tuesday
the decision to leave the troubled Middle East country was taken as the company was unable to develop the
projects due to their location in a region of "much conflict", Reuters reported.
Eni chief executive Paulo Scaroni was last week reported as saying by Upstream the Italian giant was
prepared to quit the country due to frustrations over bureaucratic delays in developing the southern Zubair
oilfield under a technical service contract. Red tape and poor infrastructure, as well as increasing security
concerns, have left some oil majors, including Eni, disgruntled with doing business in the country.
"If they do not sign the contracts in a couple of weeks we will go. We have waited six months," Scaroni was
quoted as saying on the sidelines of a conference on Tuesday.

But he added: "I am hopeful, we have no reason to believe they won't do it (sign).” Eni, as operator of
Zubair, has been forced to lower the output target for the supergiant field near Basra to 850,000 barrels per
day from a previous figure of 1.25 million bpd. Production from the field is now running at 320,000 barrels
per day compared with around 195,000 bpd in 2009 when Eni won the service contract.
Eni hopes to increase production from Zubair to 400,000 bpd by the end of this year. A Milan-based oil
analyst said of the company’s threat to quit the country: "I think it's just tactics. Eni would find it hard to
pull out since they've already invested heavily.” Industry sources said the process may be slowed due to the
distractions of national elections in April and rising violence in the western Anbar province, where Baghdad
is battling militants.
Eni has previously said every investment it makes in Iraq is subject to a bid that then has to go to different
institutions for approval. Under Iraq's service contract, the Oil Ministry must approve contract awards above
$100 million. Scaroni said at the group's strategy meeting earlier this month he believed contracts “should
be approved in 45 days”.
“It happens that it is approved in nine months, sometimes six, sometimes one year," he added. Meanwhile,
BP has had to let around 100 contractors go after the Oil Ministry failed to approve crucial contracts for its
nearby megaproject at Rumaila, Iraq's biggest oilfield. However, industry sources said the UK supermajor
has no intention whatsoever of leaving Iraq, with Rumaila now producing at its highest rate - between 1.4
million and 1.5 million bpd.
Oil companies such as ExxonMobil, which has a 25% stake in Iraq’s West Qurna 1 project, have been
beating a path to the northern semi-autonomous region of Kurdistan where more attractive production
sharing contracts are on offer and investment conditions appear more stable.
The US supermajor is set to start drilling on its Kurdistan acreage after signing exploration pacts with
the regional government,
with other major players
including Chevron, Hess,
Repsol and Marathon,
with partner Total,
following suit.
However, Baghdad has
deemed such deals with
the region as illegal under
the federal constitution
and has previously
threatened to kick
ExxonMobil out of its
Iraqi acreage unless the
company abandons its
Kurdistan blocks.

United States Oil net imports have declined sharply since 2011
http://www.eia.gov
The drop in net imports of oil (crude and petroleum products combined) was the major contributor to the
United States reaching its lowest net trade deficit in November 2013 since 2009, although the trade deficit
increased in the final month of 2013. U.S. oil trade, by far the dominant component of overall U.S. energy
trade, has seen major changes in recent years. In both absolute and percentage terms, U.S. net import
dependence measured volumetrically (in terms of barrels or barrels per day) has been declining since 2005.
Although the volume of net oil imports peaked in 2005, the value of monthly net oil imports generally
continued to rise through July 2008, when it exceeded $40 billion due to the sharp run-up in oil prices
through the first half of that year. Net import values fell sharply in the second half of 2008, as volumes fell
modestly and prices fell sharply. From early 2009 through early 2011, rising prices drove the value of net
oil imports higher, even as import volumes remained flat. Since early 2011, a falling volume of crude oil
imports as domestic production has risen sharply and the emergence of net product exports have driven
the volume and value of net oil imports lower. These reductions occurred even though the annual average
oil prices in 2012 and 2013 were at their highest historical levels.

While the United States has historically been a significant net importer of both crude oil and petroleum
products, stagnating domestic product demand combined with very competitive refinery infrastructure and
strong global product demand turned the United States into a significant net exporter of petroleum products
starting in 2011.
By value, crude oil imports were down 16% year-over-year in 2013. EIA's February Short-Term Energy
Outlook forecasts continued rapid growth in domestic crude oil production in both 2014 and 2015, which
should further reduce the volume of net crude oil imports over this period. Given the continued flatness in
domestic demand and continued access of U.S. refiners to domestic crude streams and relatively low-cost
natural gas to fuel their refineries, the country is likely to maintain its current role as a major net exporter
of distillate fuels and other products to external markets, especially those in the Atlantic Basin. The upper
limits to near-term product export growth are likely to be defined by refinery capacity, while the lower
limits to product exports likely depend on potential weakness in foreign product demand, perhaps
responding to weaker-than-expected economic conditions.

Domestic production of crude oil, including lease condensate, is projected to increase sharply in the
AEO2014 Reference case, with annual growth averaging 0.8 million barrels per day through 2016, before
leveling off and declining slowly after 2020. Net imports are also reduced by the continuing decline in U.S.
oil use as fuel economy standards for cars and light trucks become steadily more stringent through 2025.
The combination of higher oil production and lower oil consumption in the United States has already
reduced net imports as a share of U.S. liquid fuels use from 60% in 2005 to 40% in 2012, with a further
decline of the net import share to 27% in 2015 and 26% in 2020 projected in the AEO2014 Reference case.
Net import volumes of crude oil and liquid fuels on a volume basis are projected to decline by 55% between
2012 and 2020.
NewBase Comments / Research
in another article by Reuters on 13 August, “China looks to further open crude oil import market”. The
government monopoly on oil importation will be changed. According to the Chinese authorities today’s
imports of 5.7 Mb/d will increase in 2020 to 9 Mb/d, i.e. by 3.3 Mb/d. This is the same order of increase as
WoodMac’s estimate of 9.2 Mb/d in 2020.
The USA’s Energy Information Agency (EIA) has also studied future US and China oil imports and presents
its data in the figure above. In the report they write, “EIA’s August 2013 Short-Term Energy Outlook
(STEO) forecasts that China’s net oil imports will exceed those of the United States by October 2013 on a
monthly basis and by 2014 on an annual basis, making China the largest importer of oil in the world”.
Ten years ago per capita oil consumption in the USA was approximately double that of Europe. As
one of the world’s leading producers of oil the USA has, for many years, encouraged oil use with,
among other things, low taxes on oil products. Now that the price increases it is natural for the
USA to find solutions that require less oil. Therefore, it is not surprising that consumption is falling.
Even if fracking contributes only 2% of oil production from a global perspective, it has great
importance for the USA. If an oil price of $149 per barrel as foreseen by oil experts of WoodMac
for China, becomes reality then this will presumably have large economic consequences for the
EU. If the price sinks to $65 per barrel as seen in their USA calculations, then there will not be
much fracking.

Qatar has long-term commitment to UK’s energy security: al-Marri
http://www.gulf-times.com/business
Energy is a hugely politicised subject in the UK with the main industry players under mounting
pressure to keep a lid on prices not just from consumers but regulators. Now a big question is
looming over who should control the North Sea oil and gas supplies. With Scotland debating
whether it should become an independent country, the stakes over management of the remaining
reserves are rising. To the extent that Monday saw the UK cabinet convening in Aberdeen, the
heartland of the oil and gas industry, in only the second such gathering in Scotland since 1921.
Just a few miles away Ministers from the Scottish government held their own talks on this
sensitive subject. It was a case of High Noon at the gas field.
Far removed from all this political turmoil, in the South of Wales, lies an important part of the
answer to the UK’s energy needs. Energy that travels over 6,811 nautical miles from the Port of
Ras Laffan in Qatar to the deep water port of Milford Haven. Energy that arrives in state of the
art, double-hulled ships to the South Hook LNG Terminal where the liquefied natural gas (LNG) is
converted from a liquid back into a gas and delivered to the UK’s homes and business via the
national grid.
In his office overlooking the River Thames in the London Bridge Quarter, and with a view of the
Shard where the company will relocate in May, South Hook gas director and general manager,
Rashid al-Marri keeps his focus on what his company has to offer. “Our mandate is to maximise
the utilisation of the South Hook LNG terminal, and so apart from our core supply agreement with
QatarGas, we have also signed agreements with a number of other companies including RasGas,
Total, Chevron, ConocoPhillips, Axpo and Noble Group. This means that the UK has access to
additional supplies of natural gas, not just from Qatar but potentially from elsewhere in the
world,” he said.
A view of the South Hook LNG Terminal. Inset: Al-Marri: Focused

South Hook Gas has the capacity to provide around 20% of the UK’s energy supplies. Just one Q-
Max vessel supplies enough natural gas to meet London’s demand for a week. “You can see how
UK energy security has improved thanks to the arrival of Qatari LNG,” commented al-Marri.
Looking further afield he said: “Europe is no longer an energy island. Thanks to LNG, it now has
access to additional supplies from around the world. With improved interconnectivity between the
UK and Europe, the energy goes to where it is needed most. For example, in recent years, the UK
had record gas exports to Europe thanks to the liquidity in the UK market provided by Qatari
LNG.”
Asked to comment on the EU policies needed to ensure that the gas market remains viable for
gas shippers and investors, al-Marri said: “There is a need for light touch regulations which
include a technology-neutral policy. That is, if you are subsidising a new energy technology, it will
be in the expectation that this will be phased out once it becomes mature.” He also called for a
better understanding of the risks for investors. “The electoral cycle is five years but the
investment cycle is twenty-five years or more, so investors need to be able to assess the potential
for the market in the 2030s and 40s, not just 2014,” he said.
He pointed out that Qatar had made a significant, long term commitment to the UK, noting:
“When our shareholders (Qatar Petroleum International and Exxon Mobil) and the shareholders in
South Hook LNG Terminal decided to invest over £1bn in the UK to establish our businesses, it
was because they believe that the UK is an attractive long-term market with benefits for both
Qatar and the UK.”
He added: “We have a twenty-five year supply agreement with Qatargas 2. When this project was
started, it was part of a full value chain of Qatargas 2 between the offshore facilities, the
processing LNG trains in Ras Laffan,
the fleet of Q-Max and Q-Flex LNG
tankers, the South Hook LNG
Terminal and South Hook Gas. That
project was around roughly $14bn in
total. You can imagine the scale of
this project and the sophisticated
technology which was used to
construct the largest integrated LNG
value chain.” When asked about the
North Sea gas supplies, where
production peaked in 1999, al-Marri
commented: “We have seen a
decline in UK domestic natural gas
production and this means that
there is an opportunity for increased
LNG imports to meet future demand.
Natural gas has been proven to be
the cleanest fossil fuel and an
affordable and abundant, energy
source.”

BP and Socar to boost Azerbaijan ACG Full Field Development
http://www.2b1stconsulting.com
As the operator of the Azeri-Chirag-Gunashli (ACG) oil field in the Caspian Sea of Azerbaijan, Azerbaijan,
BP shared with his partners, the State Oil Company of Azerbaijan (Socar), Inpex, Chevron, ExxonMobil,
Statoil, TPAO, Itochu and ONGC Videsh, in the Azerbaijan International Operating Company (AIOC) his
recommendations to maintain production up to 2024 and beyond.
Discovered in the 1980s by the Soviets approximately 100 kilometers east of Baku by less than 180 meters
water depth in the Caspian Sea, the three crude oil fields Azeri, Chirag and Gunashli appeared quickly from
first exploration to be as large as complex to develop. The national oil company (NOC) Socar started the
first production with several shallow water platforms in 1985.
But in 1994, the Government of Azerbaijan established the AIOC joint venture to sign a 30 years production
sharing agreement (PSA) covering the development of the ACG oil and gas fields.
Led by BP, the AIOC joint venture
consolidates the working interests
of the stakeholders such as:
- BP 35.8% is the operator
- Socar 11.6%
- Chevron 11.3%
- Inpex 11%
- Statoil 8.6%
- ExxonMobil 8%
- TPAO 6.8%
- Itochu 4.3%
- ONGC Videsh 2.7%
The AIOC production sharing
agreement is supposed to last until
2024, leaving the Government of
Azerbaijan and its national flagship
Socar to take the lead afterward. In
that perspective BP mobilized all its
experience and knowledge about the ACG oil fields to figure out the potential scenari to continue their
development beyond the production sharing agreement deadline.
New Western Chirag platform to add 100 Kb/d to AIOC
With total reserves estimated to 17.4 billion barrels of oil, ACG ranks among the largest fields in the world.
At the end of the production sharing agreement, in 2024, BP estimates that only 5.4 billion barrels of oil will
have been recovered, leaving still a long life to the ACG fields.
As the ACG oil field development provides the Azeri Government with the most significant revenues, it
intends to prepare the next phase carefully to prevent any slowdown in production.
In that respect the last years experiences is rich of learning.
In completing the ACG Phase III project in 2008, the AIOC joint venture was expecting to reach 1 million
barrels per day (b/d). Since then, the production peaked up only to 823,000 b/d in 2010 and started to
decline again. Fortunately the last platform of the ACG Full Field Development program started operations
at Western Chirag on early February.

It should bring 100,000 b/d additional production of oil to the AIOC joint venture, shortly below the
targeted 1 million b/d still.
From the modelizations tested by BP through digital oil fields techniques, it appears that solutions to
prevent the early depletion of the ACG oil field should be to add two offshore production platforms to
increase the pumping operations and gas injection capacities.
In order to maintain the ACG production at the level required by the production sharing agreement, the
second platform should be in operation by 2021 at the very last limit.
Considering a minimum lead time of three to four years to design and build these platforms, BP and its
partner in the AIOC joint venture Socar, Chevron, Inpex, Statoil, ExxonMobil, TPAO, Itochu and ONGC
Videsh should make a decision to proceed with the first production platform before 2015.

NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Your partner in Energy Services
Khaled Malallah Al Awadi,
MSc. & BSc. Mechanical Engineering (HON), USA
ASME member since 1995
Emarat member since 1990
Energy Services & Consultants
Mobile : +97150-4822502
khalid_malallah@emarat.ae
khdmohd@hotmail.com
Khaled Al Awadi is a UAE NationaKhaled Al Awadi is a UAE NationaKhaled Al Awadi is a UAE NationaKhaled Al Awadi is a UAE National with a total of 24 yearsl with a total of 24 yearsl with a total of 24 yearsl with a total of 24 years of experience in theof experience in theof experience in theof experience in the Oil & Gas sector. Currently working asOil & Gas sector. Currently working asOil & Gas sector. Currently working asOil & Gas sector. Currently working as
Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation forTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation forTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation forTechnical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for
the GCC area via Hawk Energy Service asthe GCC area via Hawk Energy Service asthe GCC area via Hawk Energy Service asthe GCC area via Hawk Energy Service as a UAE operations base , Most of the experience were spent as the Gas Operationsa UAE operations base , Most of the experience were spent as the Gas Operationsa UAE operations base , Most of the experience were spent as the Gas Operationsa 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 , heManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , heManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , heManager in Emarat , responsible for Emarat Gas Pipeline Network Facility & gas compressor stations . Through the years , he has developedhas developedhas developedhas developed
great experiences in the designingreat experiences in the designingreat experiences in the designingreat experiences in the designing & constructingg & constructingg & constructingg & constructing of gas pipelines, gas metering & regulating stations and in the engineering of supplyof gas pipelines, gas metering & regulating stations and in the engineering of supplyof gas pipelines, gas metering & regulating stations and in the engineering of supplyof 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 Mroutes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many Mroutes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many Mroutes. Many years were spent drafting, & compiling gas transportation , operation & maintenance agreements along with many MOUs forOUs forOUs forOUs for
the local authoritthe local authoritthe local authoritthe local authorities. He has become a reference for many of the Oil & Gas Conferences held in the UAE andies. He has become a reference for many of the Oil & Gas Conferences held in the UAE andies. He has become a reference for many of the Oil & Gas Conferences held in the UAE andies. He has become a reference for many of the Oil & Gas Conferences held in the UAE and Energy program broadcastedEnergy program broadcastedEnergy program broadcastedEnergy program broadcasted
internationally , via GCC leading satelliteinternationally , via GCC leading satelliteinternationally , via GCC leading satelliteinternationally , via GCC leading satellite ChannelsChannelsChannelsChannels ....
NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase 26 February 2014 K. Al Awadi

New base special 26 february 2014

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