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 zones\units 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.




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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 as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as Oil & Gas sector. Currently working as

Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for Technical Affairs Specialist for Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy consultation for Technical 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 Operations a UAE operations base , Most of the experience were spent as the Gas Operations a UAE operations base , Most of the experience were spent as the Gas Operations 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 , 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 developed has developed has developed has 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 supply of gas pipelines, gas metering & regulating stations and in the engineering of supply of gas pipelines, gas metering & regulating stations and in the engineering of supply 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 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 for OUs for OUs for OUs 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 broadcasted Energy program broadcasted Energy program broadcasted Energy program broadcasted

internationally , via GCC leading satelliteinternationally , via GCC leading satelliteinternationally , via GCC leading satelliteinternationally , via GCC leading satellite ChannelsChannelsChannelsChannels . . . .

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NewBase 26 February 2014 K. Al Awadi

New base special 26 february 2014

Economy & Finance