new base special 31 july 2014

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NewBase 31 July 2014 Khaled Al Awadi

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OPEC oil output rises in July on fragile Libyan rebound By Reuters + NewBase

OPEC's oil production rose in July from June, a Reuters survey found on Wednesday, as a fragile recovery in Libyan supply outweighed fighting in Iraq and reduced output from Angola. Despite the increase, unrest in Africa and the Middle East is still weighing on supply. That could hinder OPEC's ability to boost output later in the year, when the International Energy Agency expects demand for OPEC crude to rise.

Supply from the Organization of the Petroleum Exporting Countries has averaged 30.06 million barrels per day (bpd) in July, up from 29.92 million bpd in June, according to the survey based on shipping data and

information from sources at oil companies, OPEC and consultants. This puts OPEC's output close to the group's nominal target of 30 million bpd. Outages in the group, such as inIraq and Libya, are effectively helping OPEC to balance the market, rather than voluntary cutbacks, say analysts.

"OPEC seems to be in control of its production at the moment, probably due to the external events," said Eugen Weinberg, commodities analyst at Commerzbank in Frankfurt. The 12-member OPEC pumps a third of the world's oil. In July, the largest increase has come from Libya, where supply rose by 210,000 bpd to 430,000 bpd, the survey found.

Still, a reversal of the rising production trend in the last few days, as well as battles between rival militias in the capital Tripoli and fighting in Benghazi, Libya's second city, put the extent of the recovery in doubt. "The problem with Libyan production is it is one step forward, one step back. The situation is quite unstable," Commerzbank's Weinberg said.

Top exporter Saudi Arabia raised supply modestly, in part because of a greater need for crude in domestic power plants, industry sources said. Some sources said exports had increased. Nigerian output also edged higher in July, according to export schedules and crude buyers. Of the countries with falling output, Iraq's supply declined by 70,000 bpd, as domestic crude use fell because of the closure of the Baiji refinery, which was attacked by militants in June.

Supply of Iraqi crude to world markets increased as exports from Iraq's southern terminals rose to more than 2.5 million bpd from 2.42 million bpd in June, when technical issues slowed down shipments, according to shipping data. Total estimated Iraqi production in June was revised higher to 3.15 million bpd because production in Iraq's Kurdistan region was higher than previously thought.

Iranian output slipped in July, the survey found, reflecting a lower export schedule for the month. Exports had been rising since late 2013 following a softening of Western sanctions on Iran over its nuclear work.




World oil demand in 2015 forecast to grow 1.2 mb/d saudigazette Despite some weakness in the first half of the year, the world economy continues to recover, OPEC Monthly Oil Market Report for July 2014 said. Global GDP growth in 2014 is now forecast at 3.1 percent, slightly higher than the estimated 2.9 percent for 2013. The US experienced a surprisingly large contraction in economic activity in the first quarter due to severe winter weather, leading to a downward revision in US GDP growth to 1.6 percent from 2.4 percent previously.

However, with the US economy expected to rebound and continued large monetary stimulus in the Euro-zone and Japan, the OECD is seen growing by 1.7 percent in 2014 and 2.0 percent in 2015. China’s GDP is forecast to grow by 7.2 percent in 2015 from 7.4 percent in the current year. India and other major emerging economies are forecast to recover.

This, in combination with the expected improvement in OECD economies, leads to a global GDP growth forecast of 3.4 percent in 2015. However, a number of uncertainties remain, ranging from the consequences of monetary policies in the developed economies to the threat of deflation in the eurozone, as well as the risk of geopolitical tensions and potential spillovers. World oil demand in 2015 is forecast to grow by 1.2 mb/d to average 92.3 mb/d, higher than the growth of 1.1 mb/d estimated for 2014. For the first time since 2010, OECD oil demand is expected to grow, increasing by 40 tb/d, with Americas being the only OECD region exhibiting growth. Europe is expected to decline further, but at a slower pace, while Asia-Pacific oil demand will continue to contract. Non-OECD oil demand growth is expected to be around 1.2 mb/d, coming mainly from China, the Middle East, and Other Asia.




In terms of products, consumption growth will be primarily driven by increased use of diesel oil and gasoline in the transportation industry, as well as to a lesser extent LPG and naphtha for petrochemical feedstocks. However, factors that could impact oil demand growth include the pace of economic activities in major consuming nations; the strength of substitution toward natural gas and other fuels; efforts to reduce subsidies; and ongoing policies to enhance fuel efficiency, especially in the transportation sector. Non-OPEC supply is expected to grow by 1.3 mb/d in 2015 to average 57.0 mb/d, lower than this year’s estimated increase of 1.5 mb/d. OECD Americas is expected to see the highest growth, with contributions from the US and Canada, followed by Latin America due to the increase in Brazilian production. However, a high level of uncertainty is associated with the 2015 non-OPEC supply forecast coming from geopolitical developments; regulatory and environmental concerns; and technical challenges such as sharper-than expected decline rates, particularly in tight oil plays, and unplanned shutdowns. These factors could impact supply projections in either direction. OPEC NGLs and non-conventional oils are expected to increase at a faster pace in 2015, rising 0.20 mb/d to average 6.0 mb/d, following growth of 0.15 mb/d this year. The above forecasts suggest a demand for OPEC crude of 29.4 mb/d in 2015, a decline of 0.3 mb/d from the current year. Therefore, even if next year’s world economic growth turns out to be better than expected and crude oil demand outperforms expectations, OPEC will have sufficient supply to provide to the market.




The OPEC Reference Basket increased further in June by $2.45 to $107.89/b, its highest value this year. Its year-to-date value stood at $105.30/b. Crude oil futures were sharply higher as concerns mounted that geo-political tension could disrupt oil supplies. This is despite the fact that crude oil markets were adequately supplied. The Nymex WTI front-month gained $3.35 over the month to average $105.15/b. Compared to the same period in 2013, the WTI value was significantly higher, by $7.33, at $100.84/b.

On the InterContinental Exchange (ICE), the Brent front-month gained $2.73 to $111.97/b. Year-to-date, ICE Brent, at $108.82/b, was higher compared to the same period last year. Speculators' net bets on rising Brent prices hit a record high on geo-political tension in the Middle East. Money managers increased their net long futures and options positions in ICE Brent by 18,451 lots to 242,201 contracts, the highest ever recorded by the exchange. The Brent/WTI spread closed the month at less than $7/b after having widened to nearly $10/b mid-month, when Brent was at a nine-monthpeak due to concerns over reduced exports from Iraq. The Nymex WTI was supported by positive microeconomic data from the US. The Brent/WTI spread ended the month narrower at $6.82/b. The OPEC Reference Basket (ORB) extended its previous month’s gains by nearly $2.50 in June to reach its highest value this year, uplifted by a surge in crude oil outright prices. For most of June, global crude oil markets were rattled by supply concerns due to the ongoing crises in Libya and Ukraine, while the geopolitical tension in Iraq has fuelled fears of disruption in exports from the Middle East region. This is despite the fact that crude oil markets were adequately supplied during the month. In fact, some markets were over supplied amid poor refining economics, which caused physical crude oil markets in many regions to weaken significantly. Physical crude markets were under pressure with the differentials of physical crudes to their respective benchmarks at their lowest in over a year in most markets. Moreover, these supply-related headlines and geopolitical tension in Iraq and Ukraine kept the speculators on the long side of the market, supporting a rise in prices.




Meanwhile, OPEC's oil production rose in July from June, a Reuters survey found on Wednesday, as a fragile recovery in Libyan supply outweighed fighting in Iraq and reduced output from Angola. Despite the increase, unrest in Africa and the Middle East is still weighing on supply. That could hinder OPEC's ability to boost output later in the year, when the International Energy Agency expects demand for OPEC crude to rise.

Supply from the Organization of the

Petroleum Exporting Countries has averaged 30.06 million barrels per day (bpd) in July, up from 29.92 million bpd in June, according to the survey based on shipping data and information from sources at oil

companies, OPEC and consultants. This puts OPEC's output close to the group's nominal target of 30 million bpd. Outages in the group, such as in Iraq and Libya, are effectively helping OPEC to balance the market, rather than voluntary cutbacks, analysts said. “OPEC seems to be in control of its production at the moment, probably due to the external events,” said Eugen Weinberg, commodities analyst at Commerzbank in Frankfurt. The 12-member OPEC pumps a third of the world's oil. In July, the largest increase has come from Libya, where supply rose by 210,000 bpd to 430,000 bpd, the survey found.




Beyond oil and reserves, Russia running on empty

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Beyond oil and reserves, Russia running on empty Reuters + NewBase

For all the sanctions Western leaders can throw at Russia, the biggest threat to President Vladimir Putin’s ability to back separatists in east Ukraine is something beyond his or their control: the price of oil.

With Russia’s $2tn economy heavily dependent on crude exports, oil prices are always closely monitored by the Kremlin, but the government is particularly wary now as tensions with the West mount and sanctions ratchet up. Such conflicts often push up crude prices, but as long as oil, which accounts for 40% of state revenues, remains above the average $104 per barrel written into the 2014 budget, Moscow has little immediate need to worry.

The alarm bells will start ringing if it falls significantly below $100, forcing the government to pay more attention to propping up an economy already close to recession. The International Monetary Fund warned in May that Moscow had no contingency plan for such a scenario, so a sustained tumble in the price of crude could even undermine Putin’s grip on power.




Such a scenario is not merely idle speculation; most analysts expect oil prices to fall in the coming years as new production, including from unconventional sources in North America, applies downward pressure to markets, with some forecasts going as low as $70 per barrel for Brent crude oil in 2020, down from over $105 currently. A long-term decline in prices may be unlikely given the unrest in Iraq and the limited scope for Iran to increase output due to sanctions, but any substantial fall could derail the Russian economy.

Sergei Aleksashenko, a former deputy central bank governor and now a scholar at the Higher School of Economics in Moscow, said a $10 drop in oil prices would strip 700bn roubles ($20bn), or 5%, from Russian budget revenues a year. That translates to about 1% of GDP. Local economists estimate that a $10 price drop could rob Russia of 3 to 4% in GDP growth.

“The most evident outcomes of any decline in oil price are destabilising of the balance of payments, devaluation of the rouble, rise in inflation and decline in budget revenues, decelerating of the growth,” Aleksashenko said. “It is evident that the longer the period of reduced oil prices, the more significant the impact on the Russian economy.”

A drop to $38 per barrel in the aftermath of the 2008 financial crisis sent Russian GDP falling 7.8%, and it shed $200bn of reserves within a few short months trying to defend the rouble, which still lost a third of its value. Its reserves, though still the world’s fifth largest at nearly half a trillion dollars, are more than $130bn below their level at the beginning of the 2008 crisis.

The crisis passed when prices promptly climbed, but if Moscow learned any lessons, it is not clear in its economic pronouncements. “The government only publishes a basic level of macroeconomic risk analysis to support fiscal policymaking,” the IMF said in its May report. “There is no analysis of the implications of (changes, such as in oil) for the government finances.”




The Finance Ministry manages two oil windfall revenue funds. One, the $87bn Reserve Fund, has a clear goal to patch budget holes if the need arises. Former finance minister Alexei Kudrin said in a recent interview with ITAR-TASS news agency that if oil were to fall to $80 per barrel, the fund could last for two years.

“That (reserve) is rather small,” said Anders Aslund, a senior fellow at the Peterson Institute for International Economics in Washington. If oil hits $75-$80, Aslund said “Russia would have to cut its imports, which would hit the standard of living, investment and economic growth. A decline in GDP and standard of living would be inevitable.”

Besides oil and the oil wealth stash, Russia has precious little. “The policy of recent years has led us to a point when in the current stagnation all (other) reserves have been exhausted,” said Kudrin, who helped to amass the sovereign funds during a decade of economic boom.

“Structural reforms or a (policy) manoeuvre in favour of growth are not being considered.” Keeping oil output at the current 10.5mn bpd is also essential for the budget. But the vast West Siberian deposits, which amount to about 80% of the country’s total oil output, are in decline. Some firms have already cut investment and others may follow suit as a result of the stand-off between Moscow and the West over Ukraine. Many cut investment after the 2008 crisis.

“The situation is difficult and most likely will lead to the need to revise the investment programme,” a source close to one of Russia’s largest oil producers said. “Everyone is pretending that nothing horrible is happening. It is very difficult to predict how the situation will develop.” The annexation of Crimea from Ukraine in March boosted Putin’s popularity at home to all-time highs, but the Kremlin’s ongoing involvement in Ukraine and the economic price the country is paying is making business owners uneasy.

Yet, in a country where criticism is rare and can result in exile or prison, most remain silent. “Business always adapts to the situation in which it finds itself,” Trade Minister Denis Manturov said last week, adding that the punishment on Moscow by the West is “peanuts” compared with the isolation Russia suffered in Soviet times.

Four of Russia’s leading oil producers - Rosneft, Lukoil, Surgutneftegaz and Gazprom Neft - plan to invest a total of about $50bn this year. Russia plans to spend around $150bn a year over the next 10 years to bring onstream new fields in east Siberia, the Far East and the Arctic, as well as improve oil output at mature fields, according to Energy Minister Alexander Novak.

But that requires financing, which may be tricky, given the recent sanctions, which closed US financing of longer than 90 days for Russia’s top oil producer Rosneft and leading non-state gas company Novatek. Rosneft, which paid 2.7tn roubles in taxes to state coffers last year, used North American banks to arrange most of its over $38bn in loans raised since the end of 2011.

Asian banks are unlikely to be able to fill the gap. Domestic funding capacity is limited as the central bank keeps a cap on liquidity, to avert inflation, and Western sanctions aim to restrict capital markets for Russia’s state-owned banks. Rosneft, which is preparing to start drilling in Arctic Kara Sea with ExxonMobil, declined to comment. Its capital expenditure was around 700bn roubles for this year under an oil price of below $100 per barrel.




Energy giants Exxon, Shell, Eni profits soar New Agencies + NewBase

NEW YORK – Exxon Mobil Corp. net income rose 28 percent in the second quarter on a sale of Asian assets and higher oil prices, but oil and gas production slipped 6 percent, disappointing analysts. On Thursday, Exxon reported net income of $8.78 billion in the second quarter on revenue of $111.65 billion. Last year during the same period, the company earned $6.86 billion on sales of $106.67 billion. On a per-share basis, Exxon earned $2.05, up from $1.55 last year.

Exxon, based in Irving, Texas, does not adjust results based on one-time events such as asset sales, as most analysts and companies do. Exxon’s sale of power and utility assets in Hong Kong helped increase earnings by $1.2 billion and masked weak production results. Oil and gas production fell to 3.84 million barrels of oil and gas per day from 4.15 million barrels last year. The decline was driven by the expiration of rights to a field in Abu Dhabi and natural field declines. Exxon benefited from higher oil prices in the quarter, both in the US and abroad. In the US, Exxon sold oil for an average of $98.55 per barrel, up from $93.18 per barrel in last year’s second quarter. Outside of the US, oil sold for $103.72, up from $101.54 last year. In London, Royal Dutch Shell Plc reported a 33 percent increase in quarterly earnings, beating analyst forecasts despite impairments of almost $2 billion after producing more liquids and selling at higher prices. The Anglo-Dutch oil company also raised its quarterly dividend and said the value of its share buybacks and dividends for 2014 and 2015 would exceed $30 billion. The stock rose 3 percent in early trade.




Shell’s second-quarter earnings on a current cost of supplies basis excluding one-time items were $6.1 billion, up 33 percent from a year earlier. Analysts had expected earnings of $5.46 billion. The quarter’s earnings included a net charge of $1 billion after tax with impairments of $1.943 billion related mainly to gas assets in the US.

Chief Executive Ben van Beurden is aiming to improve returns through selling assets and more selective project choices after a rare profit warning issued in January. Shell announced a second-quarter 2014 dividend of $0.47 per ordinary share, up 4 percent year on year and in line with analyst forecasts. In Milan, Italian energy giant Eni raised net profit by half in the second-quarter it reported, driven by a significant increase in cash flow from the renegotiation of long-term gas supply contracts. The company posted a net profit up 51.0 percent from the same time last year at 868 million euros ($1.16 billion), while net sales dropped by 2.7 percent to 27.353 billion euros.

CEO Claudio Descalzi said that Eni's refining and marketing business — which lost 324 million euros in the first half — was suffering from a sluggish economy in Italy and increasing competition from the Middle East, Russia and the US. “In 2014 the overall market environment has deteriorated compared to last year, in particular in the European refining sector where margins have collapsed owning to excess capacity, causing us to accelerate the restructuring of

our plants,” Descalzi said in a company statement.




Eni Enters Myanmar, Sings Two PSCs Press Release + NewBase

Italian energy major Eni on Thursday announced signing of two Production Sharing Contracts (PSC) with Myanmar Production and Exploration Company. The two onshore blocks are RSF-5 and PSC-K. Block RSF-5 covers an area of 1,292 sq km in the Salin Basin about 500 km north of Yangon, while Block PSC-K covers an area of 6,558 sq km in the unexplored Pegu Yoma-Sittaung Basin, in the central part of Myanmar.

Eni will be the operator through Eni Myanmar and will hold 90 per cent interest while Myanmar Production and Exploration Company will have 10 per cent stake.

This agreement marks Eni’s first entry into Myanmar and confirms its strategy to reinforce its presence in the South East Asia region, the Italian firm said.




Gabon: Eni announces discovery of gas and condensates offshore Source: Eni

Eni has made an important gas and condensates discovery in the Nyonie Deep exploration prospect located in Block D4, approx. 13 kms from the coast of Gabon and 50 kms from the capital city Libreville. Preliminary estimates suggest the new gas discovery is significant, with initial potential in place estimated at 500 million boe. The discovery was made in the pre-salt of Gabon through the NFW Nyonie Deep 1 well, which was drilled in 28 meters of water depth, reaching a total depth of 4,314 meters.

The well encountered a thick hydrocarbon bearing section (320 meters) in the pre-salt clastic sequence of Aptian

age. The structure, which extends more than 40 sq kms, covers two offshore exploration blocks, both operated by

Eni (with a 100% stake.) The discovery will be followed by an appraisal campaign to assess its potential, which will be

carried out shortly. In the meantime, Eni will begin studies for the potential commercial exploitation of the field.

The discovery is the outcome of Eni’s exploration campaign which the Company is carrying out in the promising pre-salt plays of West Africa. This is the third field to be discovered recently in shallow waters in such plays, after Nene Marine and Litchendjili Marine in Congo. The total estimated potential of these discoveries is approx. 3 billion boe, with potential for further improvement.

These successes reflect the Company's strategy, which is based on maintaining high stakes which allow for the replacement of reserves and quick enhancement of exploration results, in the event of a discovery. Eni has operated in Gabon through its affiliate Eni Gabon since 2009 and currently has exploration activities in 4 exploration licenses , 2 offshore (D3 and D4) and 2 onshore (E2 and F3).




Tullow Oil to relinquish its licence interests in Liberia and Sierra Leone

Source: Tullow Oil / energy-pedia

Announcing its 2014 half-yearly results on Wednesday, Tullow Oil said that, after evaluating potential options in Liberia and Sierra Leone, the Company 'made the decision not to renew its licence interests and will exit its position. Tullow’s interest in LB-15 in Liberia expired in June 2014 and its interest in SL-07B-

11 in Sierra Leone will expire in August 2014, following which Tullow will have no licence interests in either country'.

Background

Liberia: In January 2009, Tullow completed a farm-in agreement with Anadarko whereby it acquired a 25% interest in three exploration blocks offshore Liberia; LB-15, LB-16 and LB-17.To date, one exploration well has been drilled, Montserrado-1, which made an uncommercial discovery.

Following a detailed review of the results to date from its West Africa Transform Margin acreage and considering future well commitments, on 13 June 2013, Tullow relinquished its interests in Blocks LB-16 and LB-17 offshore Liberia. Tullow retained its interest in Block LB-15, which has now been relinquished.

Sierra Leone: In the third quarter of 2009, Tullow acquired a 10% interest in licence SL-07B-11 offshore Sierra Leone following a farm-in deal with Anadarko. The interest was susequently increased to 20%. In September 2009, Tullow and its partners, made a discovery at the Venus B-1 well. This discovery confirmed the existence of a working petroleum system in the Liberian basin and the Mercury-1 well in 2010 and Jupiter-1 well in 2012, further underlined the potential of the basin.




Morocco: Genel Energy spuds SM-1 well in the Sidi

Moussa block, offshore Morocco . Source: San Leon Energy

JV partner AIM-listed San Leon Energy has announced that Genel Energy has commenced drilling operations on the SM-1 well in the Sidi Moussa block, offshore Morocco. Genel has informed San Leon that the Noble Paul Romano, a semi-submersible rig, has arrived on location and that the SM-1 exploration well was spud on 30 July 2014. The SM-1 well is located 60km off the west coast of Morocco in approx. 990m of water and is expected to take between 60-90 days to drill.

Genel is the Operator of the block and holds a 60% net operated interest, San Leon holds 8.5%, Serica

Energy holds 5%, Longreach Oil & Gas holds 1.5% and ONYHM, the Moroccan National Bureau of

Petroleum and Mines, holds a 25% interest. San Leon is carried on the drilling costs of the well up to a gross cap of US$50 million.

Oisin Fanning, San Leon Chairman, commented:

'Morocco remains one of the last under-explored regions of North Africa and the spudding of the SM-1 exploration well is another step towards our understanding of this basin’s hydrocarbon potential.'

Note: According to information on the Genel Energy web site, the Noble Paul Romano rig is drilling the Nour Prospect on the Sidi Moussa block. The well is targeting prospective resources of 300 mmbbls at a 20% probability of success. The well is targeting an Upper Jurassic carbonate reef play analogous to the Cap Juby discovery and Middle Jurassic oolitic shoals.




Nonhydro renewables now routinely surpass hydropower generation Source: U.S. Energy Information Administration,

April marked the eighth consecutive month that total monthly nonhydro renewable generation exceeded hydropower generation. Only a decade ago, hydropower—the historically dominant source of renewable generation—accounted for three times as much generation in the United States as nonhydro renewable sources (wind, solar, biomass, geothermal, landfill gas, and municipal solid waste).

The recent growth in wind and solar, which reflects policies such as state renewable portfolio standards and federal tax credits as well as declining costs of technology, has been the primary driver in the increasing market share of nonhydro renewable generation. There also has been growth in geothermal and biomass sources.

October 2012 was the first month on record in which nonhydro renewable generation exceeded hydropower generation. Although this reversal was short-lived because of the significant month-to-month variation in both hydro and nonhydro resources, the trend lines began to cross each other more frequently in the past year, with the most recent reversal lasting from September 2013 through April 2014. While hydropower once again exceeded nonhydro renewable generation in May 2014 (the latest available data), EIA projects that 2014 will be the first year in which annual nonhydro renewable generation surpasses annual hydropower generation. By 2040, nonhydro renewables are projected to provide more than twice as much generation as hydropower in EIA's Annual Energy Outlook 2014 (AEO2014) Reference case, as discussed in the AEO2014 Market Trends. In other AEO cases that assume the continuation of tax credits or other policies that support nonhydro renewables, their overall generation and generation share relative to hydropower is much higher.

The dataset used to develop this article includes only generation from plants whose capacity exceeds 1 megawatt, and as a result does not include generation from most distributed solar PV capacity. Inclusion of distributed solar PV generation, which EIA estimates at roughly 10 billion kilowatthours in 2013, modestly accelerates the timing of the crossover between hydro and nonhydro renewable generation (see AEO2014).




Hydropower capacity has increased by slightly more than 1% over the past decade, although actual hydropower generation can vary noticeably by season depending on water supply conditions. Wind capacity, on the other hand, has increased nearly tenfold over that same period. Although wind often has lower capacity factors than hydropower, wind generation increased from 3% to more than 30% of total renewable generation between 2003 and 2013.

Hydropower does exceed nonhydro renewable generation in several states, particularly in the Northwest, where in 2013 conventional hydropower accounted for 69% and 56% of total electricity generation in Washington and Oregon, respectively. However, the market penetration of other renewables is growing in the United States, particularly in the Midwest and California. Between 2003 and 2013, the number of states for which nonhydro renewable generation exceeded hydropower generation, shaded green on the maps, nearly doubled—increasing from 17 to 33 over this period.




Oil prices drive projected enhanced oil recovery using carbon dioxide Source: U.S. Energy Information Administration,

In the 2014 Annual Energy Outlook (AEO2014), EIA projects that the price of oil will largely determine

whether to use carbon dioxide (CO2) enhanced oil recovery (EOR) technologies to extract additional crude

oil from existing producing fields. The injection of CO2 gas into oil reservoirs at high pressure forces the

CO2 to mix with oil. This reduces the oil's viscosity and causes the oil to increase in volume

(swell). The result is an increase in the total cumulative volume of oil produced and in the

percentage of oil-in-place that is recovered. The decision by a producer whether or not to employ this

technique depends on a number of factors, including the geophysical properties of the reservoir, the oil

within that reservoir, the cost of applying CO2 EOR, and the revenue received from additional production.

The injection of miscible (capable of being mixed) CO2 into old oil fields to recover more of the oil-in-place is an expensive undertaking. The cost of the CO2 itself can add $20 to $30 per barrel of oil produced. In addition, the producer must pay for surface facilities to separate the CO2 from the production stream and compress it back into the oil reservoir. The producer also incurs a financial cost for the time delay associated with repressurizing old reservoirs. Oil prices thus play an important role in determining whether the additional production resulting from applying CO2 EOR to old fields is sufficient to make this process commercially and economically feasible.

In the AEO2014 High Oil Price case, the West Texas Intermediate (WTI) crude oil price rises to $202 per barrel (2012 dollars) by 2040, 45% more than in the Reference case. This higher oil price increases the number of old fields that can profitably produce oil using CO2 EOR technology. Oil production in this case reaches 960,000 barrels per day by 2040, 30% more than in the Reference case, in which it reaches 740,000




barrels per day. The opposite results occur in the Low Oil Price case, with WTI prices reaching only $73 per barrel by 2040, limiting the incentive for producers to apply CO2 EOR to old fields. CO2 EOR production reaches only 480,000 barrels per day by 2040 (35% less than in the Reference case). In the Reference case,

CO2 EOR production accounts for 10% of total U.S. crude oil production, versus 12% in the High Oil Price case, and 8% in the Low Oil Price case.

The High Oil and Gas Resource case projects a CO2 EOR production of 650,000 barrels per day in 2040 (12% lower than in the Reference case). In comparison, CO2 EOR oil production is more profitable in the Low Oil and Gas Resource case, where higher oil prices result in CO2 EOR oil production that reaches 770,000 barrels per day in 2040 (4% higher than in the Reference case).




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

[email protected] [email protected]

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NewBase 31 July 2014 K. Al Awadi

new base special 31 july 2014

Economy & Finance