Norway Outstrips Russia as Western Europe’s largest Gas Supplier

Norway has overtaken Russia in terms of European gas supply, having delivered more gas to Western Europe in the first quarter of 2015, according to data from gas operators.

Norway surpassed Russian gas exports to Europe for the first time since a brief period in 2012, Reuters reported Friday comparing the figures released by Gassco and Gazprom.

Looking Beyond Iran's Sanctions - Iran's Tantalizing Oil Dynamics

Iran contains some of the largest and most attractive petroleum resources in the world, so any easing of sanctions could have a major impact on oil and gas markets in the second half of the decade.

Iran's possible re-emergence as a major exporter would force a re-ordering of the world oil market both because of the country’s location on the cost-curve and the quality of its oil.

Iran’s proved oil reserves of 160 billion barrels, almost 10 percent of the world total, rank it fourth after Venezuela (300 billion barrels), Saudi Arabia (265 billion barrels) and Canada (175 billion barrels), according to BP.

$12 billion investment unveiled by BP for Egyptian Gas Fields

British energy giant BP unveiled plans Friday to invest a record $12 billion in Egyptian gas fields with Russian partner DEA in a "vote of confidence" for the troubled nation.

The investment -- equivalent to 11 billion euros -- will be on the West Nile Delta (WND), the company said in a statement, and comes despite concern over a surge in deadly militancy in Egypt.

The London-listed group holds a 65-percent stake in the project, while DEA owns the remaining 35 percent.

Angola Hopes To Turn Around Falling Oil, Gas Output

Written by Joe Brock for (Reuters)

Angola plans to increase its oil production by 20 percent by next year after suffering a "very difficult" 2014 as costs soared, prices slumped and technical problems hit output, the state oil company Sonangol said. 
Oil output from Africa's second largest exporter and a supplier to China averaged 1.67 million barrels per day (bpd) last year, down 2.6 percent on 2013, Sonangol said in its annual results presentation on Wednesday. 
Gas output fell 29 percent after its liquefied natural gas (LNG) plant was hit by mechanical problems, helping reduce Sonangol's net income to $710 million last year, down 77 percent from 2013. 

Sonangol plans to restart LNG exports by the end of this year and boost oil production to 2 million bpd by the first quarter of 2016, an ambitious plan in a year when it will slash $4 billion of costs due to lower oil and gas prices. 
The OPEC-member has missed its oil production target of 2 million bpd for several years due to project delays and disappointing levels of investment as oil majors scaled back exploration projects due to the global economic downturn.

"2014 was a very difficult year," Sonangol CEO Francisco de Lemos Maria told reporters in Luanda. "We need to make corrections and to re-evaluate our entire implementation strategy," he added. Sonangol has secured the promise of a $2 billion loan from China to help with oil projects this year. Angola sends about half of its oil to China and Sonangol has a joint venture with Sinopec, China's second biggest energy company. Oil accounts for around half of Angola's GDP, 80 percent of tax revenues and 90 percent of export earnings. 

Beijing has issued several oil-backed loans to Angola dating back to 2003, a year after the African nation emerged from a 27-year civil war. Prior to this loan, China had lent Angola $14.5 billion since the war's end. Angola is seeking to borrow a total of $10 billion abroad this year, including issuing a debut $1.5 billion Eurobond and tapping the World Bank for $1 billion. Parliament on Wednesday passed a revised 5.4 trillion kwanza ($51 billion) 2015 budget, cutting spending by 1.8 trillion kwanza from its original plans due to a drop in oil prices . 

Angola's kwanza has weakened more than 7 percent in the last five months as oil prices weakened and foreign exchange supplies tightened. The kwanza was trading 0.3 percent weaker at 106 to the dollar by 0955 GMT, close to record lows.

Standardization: The Key To A New Subsea

Subsea processing consists of a range of technologies for separation, pumping and compression that enable production from offshore wells without the need for surface facilities. Seabed processing systems have become increasingly accepted by operators as a solution to accelerate reserves, maximize production, and reduction costs. This maximization has led to the development of marginal fields, low energy reservoirs or reservoir with poor rock or fluid properties and multiphase boosting or combination of gas/liquid separation and liquid boosting has made this more economically feasible. Benefits can be found in later life reservoirs with high water cut that are produced into constrained topsides, in which subsea processing can lead to water re-injection by-passing water choke by backpressure to increase production. For example, reservoirs with main driving mechanism of water-flooding such as that in the Campos Basin in Brazil operated by Petrobas seek to use the subsea processing to tackle the increasing water content in stream once water breakthroughs.

Faced with such formidable conditions how do oil and gas companies operate at depths of 300 metres, or even 3,000 metres below the surface? The answer is subsea wells that produce hydrocarbons via installations on the seabed. With near-shore resources already well developed, these complex technologies are enabling us to take our pursuit for resources longer, further and deeper offshore.

Given recent advances in cost-reduction (compared to surface facilities), accessibility and efficiency, the use of subsea wells has increased. For example, half of Statoil’s production now comes from 500 subsea wells. Across the industry, analysts forecast global subsea hardware capital expenditure totaling $117 billion for the next four years – a growth of more than 80% over the preceding five years.

However, in comparison with conventional technologies, cost for equipment and operations have accelerated in recent years. In fact, as a result of the extraordinary growth of subsea, costs for installations have increased by 250% in the last 10-12 years. One of the main reasons for higher costs is due to operators working with suppliers on tailor-made solutions, on a project by project basis. Recognizing this issue, the industry is exploring standardization, which will deliver volume and drive down costs (excerpt from Statoil). We might see a move from the current point-to-point subsea powering systems to a high capacity subsea power grid in power distribution system architecture.

An example would be the AKPO field in block OML 130, 200km offshore Nigeria is in 1400m water depth. It is a gas/condensate field with high pressures and high temperatures. One of the greatest challenges is to ensure that condensate and gas in multiphase flow reach the production facilities without being stopped by hydrates and wax and scale deposition. The technical challenges alone are significant, but when set against the background of increasing oil prices and high commercial pressure on the suppliers from more than one operator and more than one field, the challenges take on a new dimension. Added to that for Akpo were the issues of resources of personnel and manufacturing capacity in a very buoyant market as well as the new challenge of manufacturing in Nigeria.

The second most important issue facing all Subsea decisions is the fact that the cost of installation - whether by Drilling Rig or by Installation Vessel - FAR exceeds (in most cases) the cost of the equipment itself. Added to that is the cost of the lost production. This cost is effectively tripled if equipment has to be retrieved and then re-installed. No Subsea Engineer ever wants to see their equipment return to the surface. Nevertheless - things do go wrong even on a single well - and in a system as large as Akpo, the opportunities for something to go wrong increase. Such is the inevitable nature of large Systems. The ability to recover and install was seen as vital. Design for installation was a vital strategy in the design process. This lead to design in order to minimize installation - and retrieval - costs. [2]

Standardization is the new song in the lips of the innovative juggernauts pushing this evenly gradually accepted subsea frontier in oil and gas exploration and production. The deep sea is a truly alien place where the temperature is close to freezing and for every 10 metres of depth you reach the pressure increases by 14.5 pounds per square inches. Divers rarely exceed 180 metres and if you want to go any deeper, submersibles, robotic or manned, become the only options [1]. Coming into deep water scenarios we can say that no two fields are the same and dealing with such high commercial pressures the industry is in dying need of a template, a set of client categorized models. At this stage we need a centralized knowledge bank with synergies made to full functionality when it comes sharing and implementation of experiences to tackle the rising challenges in moving the topsides to the seabed.

Industry collaboration

Successfully achieving standardization will depend on industry collaboration. Currently several joint industry partnerships (JIP) are underway, bringing together oil and gas producers focusing on various elements of subsea technology, including the interface, underwater grid, power solutions and more. The goal of these JIPs is to develop internationally agreed industry standards.

Collaboration to achieve standardization is innovation in an uncharacteristic form. Typical conceptions of innovation are limited to small and revolutionary start-ups, or large ‘game-changing’ technologies. However, for subsea, innovation is about ensuring the long-term feasibility of existing technology. In the world of subsea, standardization is the new innovation.

It's a stage in the evolution of overcoming new frontiers on the deep water end of this industry and the sooner standardization is birthed and accepted in future developments the earlier we can start to feel the economies of scale to a cost-benefit advantage.

[1] The FInal Frontier: Conquering The Seabed (2014) www.statoil.com

[2] AKPO: The Subsea Production System (2010) Stuart GrahamNelson (Total Upstream Nigeria)