HOUSTON, Aug. 18, 2014 /PRNewswire/ -- Apache Corporation (NYSE, Nasdaq: APA) today announced an oil discovery at the Phoenix South-1 well - the company's first discovery in Australia's offshore Canning Basin.

Wireline and formation pressure tools have confirmed at least four discrete oil columns ranging in thickness between 85 and 151 feet (26 to 46 meters) in the Triassic Lower Keraudren formation, within an overall, sand-rich section between 13,648 and 14,763 feet below sea level (4,160 to 4,500 meters).

Six light oil samples have been recovered from three intervals to date; permeability measurements from the sampled zones indicate a productive oil reservoir with preliminary estimates that there might be as much as 300 million barrels of oil in place.* Evaluation of the formation penetrated in the Phoenix South-1 is under way, and final calculation of hydrocarbon pay will depend on additional analysis.

The Phoenix South-1 well is located in permit WA-435-P, offshore western Australia, 110 miles (180 km) north of Port Hedland in 435 feet (133 meters) of water. Apache has a 40-percent interest and operatorship of WA-435-P and the adjacent permit WA-437- P; co-venturers are Carnarvon Petroleum (20 percent), Finder Exploration (20 percent) and JX Nippon (20 percent). Apache also has exercised its option to acquire 40-percent interest and operatorship of two additional adjacent permits (WA-436-P and WA- 438-P) for a total position of more than 5 million acres (20,000 square kilometers).

The area includes a number of large, undrilled structures, including the Roc prospect on WA-437-P, with potential to be significant additional oil accumulations. Further drilling and evaluation is planned for 2015.

"Although evaluation is at an early stage, Phoenix South-1 is an exciting result," said Thomas E. Voytovich, Apache's executive vice president and chief operating officer - International. "The oil and reservoir quality we have seen point to a commercial discovery. If these results are borne out by further appraisal drilling, Phoenix South may represent a new oil province for Australia. We look forward to working with our partners to continue evaluation of the area."

* Oil in place estimate based on 10th percentile probability.

Forward-looking statements

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements can be identified by words such as "anticipates," "intends," "plans," "seeks," "believes," "estimates," "expects," and similar references to future periods. These statements include, but are not limited to, statements about future plans, expectations, and objectives for Apache's operations, including statements about drilling plans in Australia. While forward-looking statements are based on assumptions and analyses made by us that we believe to be reasonable under the circumstances, whether actual results and developments will meet our expectations and predictions depend on a number of risks and uncertainties which could cause our actual results, performance, and financial condition to differ materially from our expectations. See "Risk Factors" in our 2013 Form 10-K filed with the Securities and Exchange Commission for a discussion of risk factors that affect our business. Any forward-looking statement made by us in this news release speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future development, or otherwise, except as may be required by law.

Marathon Oil Corporation (NYSE: MRO), through its wholly owned subsidiary Marathon Oil Exploration Limited, announced today it has signed an exploration and production sharing contract (EPSC) for Gabon offshore Block G13, which was named Tchicuate upon signing, located in the deepwater, pre-salt play. The Company was the high-bidder on the block in Gabon's licensing round in October 2013.

"We're pleased to finalize the EPSC on the newly named Tchicuate Block, which is located in the high-potential, pre-salt play offshore Gabon," said Mitch Little, Marathon Oil vice president, International and Offshore Exploration and Production. "The addition of the Tchicuate Block aligns well with our strategic focus of capturing quality and material resource in proven and emerging oil provinces, and adds depth to the Company's exploration portfolio, following our 2013 Diaman-1B discovery on the Diaba Block offshore Gabon."

The Tchicuate Block encompasses 275,000 acres with water depths ranging from approximately 3,250 to 8,250 feet. It is located approximately 50 miles offshore the coast of Gabon and near proven shallow-water, pre-salt oil discoveries. Marathon Oil holds a 100 percent participating interest and operatorship in the block. In the event of development, the Republic of Gabon will assume a 20 percent financed interest in the contract upon commencement of production. The State holds additional rights to participate in the block in the future as a co-investor.

Marathon Oil also holds a 21.25 percent working interest in the non-operated Diaba License G4-223, encompassing 2.2 million gross acres, where the Diaman-1B discovery was made in 2013.

2H Offshore, an Acteon company, has been appointed by Heerema Marine Contractors (HMC) to engineer hybrid risers for Total's Kaombo Block 32 project. HMC, together with consortium partner Technip, were awarded the contract for the EPCI and pre-commissioning of the SURF scope for the Kaombo development by Total.

2H Offshore has been pioneering riser analysis, design and engineering for more than 20 years and with this capability and experience, 2H will perform part of the detailed engineering of the 18 Single Top Tensioner Risers (STTRs) selected for the Kaombo development. 2H will work closely with HMC as a part of an integrated design team, with 2H responsible for the engineering of the Buoyancy Tank, Upper Riser Assembly and Lower Riser Assembly packages together with Global Analysis and Systems Engineering of the risers.

The Kaombo development, located offshore Angola in water depths extending from 1425m to 1925m, will include the Gindungo, Gengibre, Canela, Louro, Mostarda west and Caril fields tied back to two turret-moored FPSOs. The selected concept consists of a number of production loops with one insulated production riser and one non-insulated service riser per field. Water injection risers will also be required.

The project is currently in the detailed engineering stage with 2H also contracted to support HMC through the procurement, fabrication and installation phases.

Alex Rimmer, director of 2H's Woking office, said "2H is proud and excited to be engineering the risers for the largest subsea field development project in the world. This award and other recent awards confirm 2H as the leading contractor for the engineering, design and analysis of a range of production riser technologies including hybrid, steel catenary, top tensioned and flexible riser systems. With a history of working together, we look forward to engaging with HMC on this and future projects."

The Bureau of Safety and Environmental Enforcement (BSEE) initiated a day long unannounced drill involving Murphy Exploration and Production Company last week. The exercise tested Murphy's ability to respond to a simulated spill event in accordance with its Oil Spill Response Plan (OSRP).

The scenario simulated was a loss of well control 75 miles off the coast of Louisiana. As part of the exercise an incident command center was established in Slidell, La. and oil skimming recovery equipment was deployed aboard the Mississippi Responder from Pascagoula, Miss. Once at the designated location, testing of the skimmer was conducted along with the placement of oil containment boom arranged in a J formation. Representatives from the U.S. Coast Guard, NOAA and the Alabama Department of Environmental Management participated in the BSEE led exercise.

These exercises are conducted in accordance with 30 CFR Section 254.42(g) as authorized by the Oil Pollution Act of 1990. Following an exercise, BSEE and other participating agencies review the day's events, identify lessons learned and provide appropriate regulatory feedback to help improve operators' approved OSRPs. The first exercise was conducted by the Department of the Interior on July 25, 1989, with an offshore oil and gas operator in the Gulf of Mexico.

Norwegian prime minister Erna Solberg officially opened the Gudrun platform in the North Sea 19 August. This is the first new Statoil-operated platform on the Norwegian continental shelf (NCS) since Kristin in 2005.

Gudrun is the first in a long line of new field developments operated by Statoil, and therefore it represents a new era on the NCS.

The next in line is Valemon, which is scheduled for start-up later this year. Gina Krog and Johan Sverdrup on the Utsira High are next in the North Sea.

We also have Aasta Hansteen and Johan Castberg to come in northern Norway. Johan Sverdrup alone will ensure value creation for another 40-50 years from the NCS.

Global strategy

Gudrun is the result of a global development strategy. The jacket has been delivered by Kværner Værdal in mid-Norway, and the living quarters by Apply Leirvik at Stord in western Norway.

The topside was provided by Aibel with sub-supplies from Thailand, Poland and from Haugesund in Western Norway. The helideck was constructed in China.

Gudrun has been put on stream on time and below the cost estimate of the plan for development and operation (PDO). The global puzzle has helped keep the costs down.

The development has demonstrated the strong competitiveness of the Norwegian supplier industry.

“Gudrun has proven that we are able to take our industry into a new era with global competition and local value creation,” said Statoil’s chief executive Helge Lund in his speech at the opening.

Using the infrastructure

On Gudrun, Statoil has combined a new field development with existing pipelines and facilities. The oil and gas from Gudrun is processed on the Sleipner A platform which is located 50 kilometres further south. The gas is then piped to Europe, while the oil is piped along with the Sleipner condensate to the Kårstø processing complex north of Stavanger for shipment.

“Gudrun is a good example of how we manage to realise projects by combining new field developments with existing infrastructure. This is good value creation that helps maintain activity and extends the life of a wide range of offshore fields and facilities,” said Lund.

The recoverable reserves on Gudrun are about 184 million barrels of oil equivalent. The platform already produces 30,000 barrels per day.

BP Trinidad and Tobago LLC has announced the sanction of its Juniper offshore gas project

The project will feature the construction of a normally unmanned platform together with corresponding subsea infrastructure, a first for BP Trinidad and Tobago. Fabrication is proposed to begin in 4th quarter, 2014.

The Juniper facility will take gas from the Corallita and Lantana fields located 50 miles off the south east coast of Trinidad in water-depth of approximately 360 feet. The development will include five subsea wells and will have a production capacity of approximately 590 million standard cubic feet a day (mmscfd). Gas from Juniper will flow to the Mahogany B hub via a new ten kilometer flowline.

Juniper will become bpTT's 14th offshore production facility. Drilling is due to commence in 2015 and first gas from the facility is expected in 2017.

BPTT Regional President Norman Christie said: "Juniper demonstrates bpTT's commitment to Trinidad and Tobago over the long-term. This development is an important part of the future for bpTT because it will assist the company in meeting its natural gas commitments to the market. It is also an important step change for bpTT as it introduces subsea infrastructure to continue the development of its resources in the Columbus Basin."

BPTT operates in 904,000 acres off Trinidad's east coast. BPTT has 13 offshore platforms and two onshore processing facilities.

The Juniper project has been undertaking Front End Engineering and Design (FEED) activities since 2012.

Northern Offshore, Ltd. (Oslo BØrs: NOF.OL) has announced that the company has finalized a 2 ½ year contract with Rosneft Oil Company, in conjunction with North Atlantic Drilling Ltd., for the provision of the jackup drilling rig Energy Endeavour.

According to the agreement, any break rights expire after 100 days, after which the contract will commence in direct continuation upon the release of the rig by the current client. The company estimates the contract value to be in excess of US$150 million, exclusive of any mobilization fees.

Gary W. Casswell, Northern Offshore's president and CEO, said "This is an exciting opportunity for the company, and we are delighted that Rosneft has selected Northern Offshore and the Energy Endeavour for this program. We look forward to working with them and achieving a safe and successful drilling campaign."

Statoil has been awarded interest in the COL4 license offshore Colombia in the Caribbean Sea in the2014 Colombia Licensing Round.

Statoil will hold 33.33% in the license. Repsol will be the operator of the license and will hold 33.34%. ExxonMobil Exploration Colombia will hold 33.33%.

The award is subject to the final approval of the National Hydrocarbons Agency of Colombia (ANH).

"Deepwater offshore Colombia is virtually untested. The award of new acreage in this frontier area is in line with our exploration strategy of early access at scale", says Nick Maden, senior vice president for Statoil's exploration activities in the Western Hemisphere.

The license award represents a country entry for Statoil into Colombia. The entry is an early exploration phase and the initial working commitments include 2D and 3D seismic acquisition which will allow Statoil to further assess the potential of the basin.
There are no well commitments during the first exploration phase.

The Bureau of Ocean Energy Management (BOEM) issued an Advanced Notice of Proposed Rulemaking (ANPR) on Risk Management, Financial Assurance, and Loss Prevention to seek public input as it considers modernizing its risk management program and bonding regulations for offshore oil and gas operations on the Outer Continental Shelf. This first step initiates a dialogue about BOEM’s existing regulations, which are approximately 20 years old and have not kept pace with offshore infrastructure developments, including deepwater operations, current industry practices, and the growing costs of decommissioning.

“We would like to work with industry and others to determine how to improve our regulatory regime to better align with the realities of aging offshore infrastructure, hazard risks, and increasing costs of decommissioning,” said BOEM acting Director Walter D. Cruickshank. “Today’s action is an important first step in initiating a dialogue on how to best enhance our risk management program to better match current practices, with the ultimate goal of ensuring that industry meets its decommissioning responsibilities and the burden of decommissioning a facility on the Outer Continental Shelf does not fall to taxpayers.”

Existing regulations require lessees on the Outer Continental Shelf to provide bonds or other alternative forms of financial assurance to cover current and future operations, such as decommissioning oil and gas infrastructure. Since the current bonding requirements were set nearly a quarter of a century ago, offshore operations have changed significantly, such as increased advancements in the scale and complexity of deepwater and subsea operations, and the costs of decommissioning have dramatically increased. In light of the infrastructure and operational changes, BOEM has recognized the need to update its requirements and develop a comprehensive program to assist in identifying, prioritizing, and managing the risks associated with industry activities on the Outer Continental Shelf.

BOEM is seeking stakeholder comments regarding various risk management and monitoring activities related to offshore energy development on the Outer Continental Shelf. The advanced notice of proposed rulemaking seeks comment on the bonding and financial assurance program for BOEM's offshore oil and gas program. The bureau is also accepting comments on the analogous bonding and financial assurance program for BOEM's offshore renewable energy and hard minerals programs. The notice also solicits comments on best practices to mitigate risks, as well as whether, or to what extent, the current forms of financial assurance are adequate and appropriate.

The Advanced Notice Proposed Rulemaking will be published in the Federal Register on Aug.19, 2014 and available for public viewing the day before. The ANPR includes a 60-day comment period which will close at midnight on Oct. 20, 2014. After the comment period closes, BOEM plans on continuing its outreach and hosting a workshop with stakeholders to have additional opportunities for discussion as it considers options for proposed regulations.

Rice University experiments visualize methods for enhanced recovery from wells

A Rice University laboratory has provided proof that foam may be the right stuff to maximize enhanced oil recovery (EOR).

In tests, foam pumped into an experimental rig that mimicked the flow paths deep underground proved better at removing oil from formations with low permeability than common techniques involving water, gas, surfactants or combinations of the three.

The open-access paper led by Rice scientists Sibani Lisa Biswal and George Hirasaki was published online by the Royal Society of Chemistry journal Lab on a Chip.
Oil rarely sits in a pool underground waiting to be pumped out to energy-hungry surface dwellers. Often, it lives in formations of rock and sand and hides in small cracks and crevices that have proved devilishly difficult to tap. Drillers pump various substances downhole to loosen and either push or carry oil to the surface.

Biswal's lab has learned a great deal about how foam forms. Now, with an eye toward EOR, she and her colleagues created microfluidic models of formations -- they look something like children's ant farms -- to see how well foam stacks up against other materials in removing as much oil as possible.

Foam sent through a microfluidic model created at Rice University shows its ability to remove oil (pink) from low-permeability formations. Rice scientists conducted experiments to see how foam would compare with water, gas or combinations of the two for use in enhanced oil recovery. (Credit: Biswal Lab/Rice University)

The formations are not much bigger than a postage stamp and include wide channels, large cracks and small cracks. By pushing various fluids, including foam, into test formations, the researchers can visualize the ways by which foam is able to remove oil from hard-to-reach places. They can also measure the fluid's pressure gradient to see how it changes as it navigates the landscape.

The team determined the numbers are strongly in foam's favor. Foam dislodged all but 25.1 percent of oil from low-permeability regions after four minutes of pushing it through a test rig, versus 53 percent for water and gas and 98.3 percent for water flooding; this demonstrated efficient use of injected fluid with foam to recover oil.

The less-viscous fluids appear to displace oil in high-permeability regions while blowing right by the smaller cracks that retain their treasure. But foam offers mobility control, which means a higher resistance to flow near large pores.

"The foam's lamellae (the borders between individual bubbles) add extra resistance to the flow," said Biswal, an associate professor of chemical and biomolecular engineering. "Water and gas don't have that ability, so it's easy for them to find paths of least resistance and move straight through. Because foam acts like a more viscous fluid, it's better able to plug high-permeable regions and penetrate into less-permeable regions."

Charles Conn, a Rice graduate student and lead author of the paper, said foam tends to dry out as it progresses through the model. "The bubbles don't actually break. It's more that the liquid drains away and leaves them behind," he said.

Drying has two effects: It slows the progress of the foam even further and allows surfactant from the lamellae to drain into low-permeability zones, where it forces oil out. Foam may also cut the sheer amount of material that may have to be sent downhole.

One of the challenges will always be to get the foam to the underground formation intact. "It's nice to know that foam can do these things, but if you can't generate foam in the reservoir, then it's not going to be useful," Conn said. "If you lose the foam, it collapses into slugs of gas and liquid. You really want foam that can regenerate as it moves through the pores."

The lab plans to test foam on core samples that more closely mimic the environment underground, Biswal said.

Kun Ma, a Rice alumnus, co-authored the paper. The Department of Energy, the Abu Dhabi National Oil Co., the Abu Dhabi Oil R&D Sub-Committee, the Abu Dhabi Co. for Onshore Oil Operations, the Zakum Development Co., the Abu Dhabi Marine Operating Co. and the Petroleum Institute of the United Arab Emirates supported the research.

Saipem has been awarded new drilling contracts in Indonesia, Nigeria, the Arabian Gulf and Latin America worth approximately $850 million of which $540 million are related to offshore activity and refer to four different units of Saipem's fleet.

Saipem has signed with Eni Muara Bakau B.V. a contract for the utilization of the Scarabeo 7 which will be operating offshore Indonesia drilling a minimum of 12 wells; the project is estimated to be completed in first quarter 2017. The vessel will remain under contract with Eni until February 2018. Scarabeo 7 is a fifth generation semi-submersible drilling rig, capable of operating in water depths of up to 5,000 feet.

Furthermore, in West Africa the contract for the Scarabeo 3 has been extended to March 2015. Scarabeo 3 is a second generation semi-submersible drilling rig, with capacity to operate in water depths of up to 1,500 feet.

In addition, NDC has extended the contract for the jack-up rig Perro Negro 2 for 24 months, starting from January 2015, for activities in the Arabian Gulf. In Ecuador, EP Petroamazonas has extended by 10 months the charter of the jack-up rig Ocean Spur, operated (not owned) by Saipem until the end of the first quarter of 2015. Both these jack-up are rigs capable to operate in water depths of up to 300 feet.

In relation to onshore drilling, Saipem has been awarded by different clients new contracts worth approximately $310 million, relating to 31 drilling rigs in South America: 21 in Venezuela, 7 in Peru, 2 in Colombia and one in Ecuador. The contracts have been signed under different terms, varying from three months to two years, and starting at different times during 2014.

Saipem operates in the Engineering & Construction and Drilling businesses, with a strong bias towards oil & gas-related activities in remote areas and deep-waters. Saipem is a leader in the provision of engineering, procurement, project management and construction services with distinctive capabilities in the design and execution of large-scale offshore and onshore projects, and technological competences such as gas monetization and heavy oil exploitation

McDermott International, Inc. (NYSE: MDR) ("McDermott") has announced that one of its subsidiaries was awarded a contract to provide transportation and installation services to Walter Oil & Gas Corporation ("Walter") for the Megalodon platform destined for South Timbalier Block 311 in the Gulf of Mexico. The project is expected to be included in McDermott's third quarter 2014 backlog.

The McDermott heavy-lift vessel, Derrick Barge 50, will install the Megalodon platform in 391 feet of water, over an existing well site in the Gulf of Mexico. (Photo: Business Wire)

"McDermott is pleased to work again for Walter to support its drilling and production activities," said Dominic Savarino, Vice President and General Manager, Americas. "This project supports our goal to maximize our asset utilization between large contracts through short term transportation and installation work."

McDermott will provide all materials and equipment to transport and install the six-pile platform in 391 feet of water, over an existing well site. The heavy-lift Derrick Barge 50 will perform a side-lift of the 3,300-ton jacket and set the 2,100

WASHINGTON, D.C., August 18, 2014 – Platts – Surging U.S. oil production is sending ripples through the crude oil market -- in prices, trade flows and the downstream, the International Energy Agency's (IEA) top oil official said Sunday on Platts Energy Week.

U.S. production is expected to reach 8.5 million barrels per day (b/d) this year and 9.3 million b/d in 2015, almost double 2008's output of 5 million b/d, said Antoine Halff, the head of the IEA's oil industry & markets division.

"On prices, the surge in production has really offset the production [loss] we've experienced in places like Libya, Iran, and so on," he said. "So that's why prices have not risen more than they have. They've been fairly stable, remarkably stable, given all the turmoil in the Middle East and elsewhere."

Crude oil that had been imported into the U.S. can now be imported by other countries, Halff said.

"There's been a tremendous remapping of the oil trade flows, if you like," he said. "And now Asia is supposed to really become the magnet for global crude traded internationally. That's a big change. China is now importing more crude than the U.S., for instance."

Downstream, new refineries under development in the U.S., increased refinery runs and the installation of more and more modern processing units, have resulted in a surge in output of U.S. product exports, Halff said.

"In U.S. refining, it's really been a revolution in a way," he said. "But these changes have taken place against a background of changes elsewhere as well for other reasons. Rapid growth in refining capacity in the Middle East, in India, in China, and so on."

Upstream, about 60% of the Organization of Petroleum Exporting Countries’ (OPEC) incremental capacity growth over the next five years is supposed to come from Iraq, the cartel's second-largest producer, according to the IEA. But that growth is "seriously at risk" because of the uncertainty and political strife in Iraq, Halff said.

"We have to wait and see," he said. "We took down our forecast of Iraqi production even before the surge in violence started earlier last month. So we've reduced our forecast of Iraqi production for the next five years by about half a million barrels."

The forecast does not take into account jihadist group Islamic State's campaign in Iraq, but "reflects other problems that Iraq has -- red tape, corruption, bottlenecks, lack of infrastructure, and so on," Halff said.

Should the expected Iraqi output not materialize, Saudi Arabia could step in, Halff said, but noted the country's current plans for capacity development likely won't result in higher net capacity for OPEC's largest producer, Halff said.

"What we've seen, our assessment of Saudi plans at this point, is that all the new capacity that will come online will essentially replace capacity that's being mothballed or that's being allowed to rest," he said. "But if Saudi chose to increase capacity, it would be able to do so."

While the IEA sees "some growth" in the United Arab Emirates, "elsewhere in OPEC we see problems," Halff said. "We see flat production growth. Or we see even declines in places like Algeria and Kuwait."

The "real game changer" has been oil production from shale reserves, starting with the U.S., Halff said.

"I think the shale revolution could not have happened anywhere else than in the U.S.," he said. "It's no accident that this happened in the U.S. Because the U.S. has a unique combination of assets, not only geological resources, but also business culture, enterprising spirit, infrastructure in place, a lot of technological know-how, skilled labor, the right environmental structure, the right investment climate. All these factors could not be found in the same combination in any other country.

"But there's nothing that prevents other countries now that the technology has been developed to adopt it and to try to replicate the success of the U.S.," he continued.

"Chief among them is Canada, of course," Halff said. "Mexico is a candidate. But [that would] probably be more in the next decade than in the next five years. We see a little bit of growth in the next five years. But not so much. We see more growth probably in Argentina, more growth in Russia and probably a little bit of growth in Australia towards the end of the decade."

The IEA sees U.S. crude oil production hitting a plateau over the next five to seven years, Halff said, adding that the surge in U.S. production is not going to be the answer to the world's energy needs.

"There's a need for investment in OPEC," he said. "There's a need for investment in the Middle East. So there's no room for complacency. This surge in production is phenomenal. It's a game-changer in many ways. But that doesn't mean that we don't need the traditional suppliers anymore. We need them very much."

Other Program Highlights

Also on the program, Katherine Hammack, the U.S. Army’s assistant secretary for installations, energy and environment, joined the program for an extended discussion on the dramatic transformation of the U.S. Army's energy consumption. View part 1 here and part 2 here.

During Sunday’s “Market Spotlight” segment, Platts Senior Managing Editor Richard Capuchino Jr. discussed the growing popularity of Vasconia, one of Colombia’s top-exported crude oil grades.

Platts Energy Week airs at 8 a.m. U.S. Eastern time Sunday mornings on WUSA9 in greater Washington, D.C., and in Houston on KUHT, a PBS affiliate, as well as on other PBS stations in cities throughout the U.S., including Anchorage, Billings, Houston, Juneau, Las Vegas, Minneapolis, San Francisco, Raleigh and Wichita. For online viewing, the program is accessible at www.plattstv.com.

The program features interviews with leading figures from government, industry, markets, think tanks and the financial community. Host Bill Loveless is an editorial director at Platts who brings 30 years of energy journalism experience to the anchor chair. The program also features veteran energy news editor and Platts Energy Week Senior Correspondent Chris Newkumet.

Platts Energy Week is produced by Platts, the world’s leading source of information and intelligence on energy and related commodities and a division of McGraw Hill Financial [NYSE: MHFI] and WUSA TV, the Washington, D.C., CBS affiliate and flagship television station of Gannett Company. [NYSE: GCI]. While the program is U.S. focused and produced in Washington, it reflects the global vantage point of Platts, whose correspondents are stationed in such major capitals as London, Dubai, Singapore, Tokyo and Moscow.

Guest booking for Platts Energy Week and related inquiries should be addressed to this email: This email address is being protected from spambots. You need JavaScript enabled to view it.. Additional information about Platts and the energy sector can be found at www.platts.com. 

Shell subsidiary in Nigeria, Shell Nigeria Exploration and Production Company Ltd (SNEPCo) started oil production from the first well at the Bonga North West deep-water development off the Nigerian coast on Tuesday 5 August 2014, another milestone for the country's energy industry.

"This is an excellent addition to our deep-water portfolio – a key growth theme for Shell's world-wide upstream business," said Andrew Brown, Shell's Upstream International Director. "It's also good news for Nigeria, as it is a new source of oil revenues and strengthens Nigeria's deep-water expertise, a key driver of economic development."

The Bonga project, which began producing oil and gas in 2005, was Nigeria's first deep-water development in water depths over 1,000 meters. Bonga North West represents a significant step forward for the project.

Oil from the Bonga North West sub-sea facilities is transported by a new undersea pipeline to the existing Bonga floating production, storage and offloading (FPSO) export facility. The Bonga FPSO has been upgraded to handle the additional oil flow from Bonga North West which, at peak production, is expected to contribute 40,000 barrels of oil equivalent per day, helping to maintain the facility's overall output.

Four oil producing wells and two water injection wells in the Bonga North West development will be connected to the FPSO, from where oil is loaded onto tankers for shipping around the world.

The Bonga North West project is part of Shell's long-standing commitment to developing deep-water engineering skills in Nigeria. The investments made by SNEPCo and its other project partners in the Bonga North West project include upgrades of local contractors' facilities and providing specialized training for Nigerians to work in the energy industry.

The Bonga project is operated by SNEPCo, which holds a 55% stake. The other project partners are Esso Exploration & Production Nigeria (Deepwater) Limited (20%), Total E&P Nigeria Limited (12.5%) and Nigerian Agip Exploration Limited (12.5%) under a Production Sharing Contract with the Nigerian National Petroleum Corporation.

Facts about the Bonga North West project:
• A number of new production manifolds, subsea umbilical systems, oil production and water injection flowlines and subsea tree systems were installed on the sea bed around 1,000 meters below the surface.
• A significant part of the project was carried out by Nigerian companies, including a local contractor that fabricated and installed the FPSO topsides.
• The project leadership and majority of staff working on the Bonga North West project are Nigerian – testament to the growth of deep-water engineering experience in SNEPCo.
• The project has been implemented according to high safety standards. SNEPCo and contractor staff worked in 10 locations in the USA, Europe and Nigeria on various aspects of the project.
SNEPCo was incorporated in 1993. The company holds interests in four deep-water blocks, two of which it operates: OML 118 (Bonga) and OML 135 (Bolia).
• More information on the Bonga project is available online here (PDF, 224 KB) - opens in new window

On Monday 28 July the topsides were lifted into place on the steel jacket on the Valemon field in the North Sea.

The Valemon topsides landed on the jacket just before 13.00. (Photo: André Osmundsen/Statoil)

Produced by Samsung Heavy Industries this is the first Statoil topsides built in South Korea.

The structure sailed from the yard on 15 June this year, and after a quick stop in Åmøyfjorden, Stavanger, last Saturday, it headed out to the field. The transportation to Norway took 40 days.

"This is a major milestone for the project, the most important milestone of course being start-up towards the end of the year," says Bjørn Laastad, vice president for Valemon field development.

The lift of the 9 750-tonne topsides took two hours, and was performed slightly earlier than initially assumed.

Thanks to good weather in the North Sea this summer, the Saipem 7000 crane vessel was available for lifting once the topsides arrived in Norway. The weather was favorable also when the crane vessel and the topsides arrived on the field.

"We had almost perfect lifting conditions," Viktor Nilsen-Nygaard, head of Valemon transportation and installation, reports from the crane vessel.
After the topsides were lifted into place, the flare boom was installed.

VIDEO: Valemon in Åmøyfjorden. Prior to the heavy lift the Valemon topsides visited Åmøyfjorden in Stavanger. https://www.youtube.com/watch?v=pjT7cld8KjU

Precision work
The more than two-year planning period has included very thorough safety evaluations for all phases of the lifting operation. From mid-June the West Elara rig pre-drilled production wells through the jacket on the field.

The rig's derrick has been pulled in during the lifting operations. During the lift the distance between the topsides and rig was just five meters.
The well operations will resume in mid-October. According to plan three wells will be producing when the field comes on stream at the end of the year. The rig's job, however, will be far from finished. Drilling on the field is planned to continue until 2017.

Hook-up
In the months ahead commissioning work will take place on the field. Wells will be hooked up with production facilities on board, sea water pumps will be installed, and electricity, water and pipelines will be connected.

Two hours after the Valemon topsides were lifted off the transport vessel, the structure landed on its feet. (Photo: André Osmundsen/Statoil)

Valemon will be powered from Kvitebjørn, and the cable has already been laid on the seabed. So have the pipelines that will be transporting gas and condensate to Heimdal and Kvitebjørn, respectively.

"Some work remains before we are ready for start-up, but we are on track," says Laastad.
In order to accommodate everyone involved in the commissioning and hook-up work Statoil has chartered a flotel.
The project thus has bed capacity for some 400 people, which is the number expected to be offshore, at least in the most hectic period. But there is one thing that cannot be planned – and that's the weather.

"If we get much poor weather the flotel must be disconnected in periods. Poor weather also creates problems for the helicopter traffic, and may delay the commissioning work. So far, however, we have been lucky with the weather, and I hope this continues", says Laastad.

Win-win
Valemon will utilize existing installations and pipelines for gas and condensate export. The gas from Valemon will be transported through the existing pipeline from Huldra to Heimdal, which is a hub for transportation further to the gas markets in Europe.

The condensate will be piped to Kvitebjørn for stabilization, and transported from there to the Mongstad refinery near Bergen.
This is a win-win situation which reduces the costs for the Valemon development, and gives Heimdal and Kvitebjørn new tasks. At Heimdal major upgrading has taken place which significantly extends the platform's life.

Facts about the Valemon Field

- Gas and condensate field in the North Sea, between Kvitebjørn and Gullfaks South. The field is located some 160 kilometers west of Bergen.



– The recoverable reserves on the Valemon field are estimated at 192 million barrels of oil equivalent.



– When all wells have been drilled in 2017 Valemon will become a normally unmanned platform, remotely controlled from Sandsli in Bergen. This is the first Statoil-operated platform to be remotely controlled from land.



– The plan for development and operation (PUD) of the Valemon field was approved by the Ministry of Petroleum and Energy in June

Statoil resumed oil and gas production on the Njord A platform in the Norwegian Sea on 19 July, after a major reinforcement of the platform structure. Production has been shut down since last summer.

The Njord A platform in the Norwegian Seat. (Photo: Øyvind Nesvåg)

Extensive analyses and inspections in 2013 revealed a need to reinforce the Njord A platform structure. To be on the safe side, Statoil opted to keep production shut down until the reinforcements were in place.

"We have extended Njord's lifetime by improving recovery on the field, and by finding more oil and gas in the area. The Njord A platform has been with us the entire time, and we want to make sure that the structure can withstand the loads it will be exposed to," says head of Njord operations Arve Rennemo.
The work that has been done through the winter and spring has strengthened the structure, so the platform can resume production. The work of reinforcing the structure has mainly consisted of bracing the primary beams and struts, and increasing the length of the secondary beams under the platform.

The long-range plan is to further bolster the platform to prepare it for future drilling operations and an extended lifetime on the Njord field.

"Njord A will produce oil and gas until the summer of 2016, after which it will be taken to shore for additional upgrades which will allow us to use the drilling system on board, and prepare it for many more good years of service on the Norwegian shelf," says Rennemo.

Statoil also has studies in progress to assess how the Njord area and the Haltenbanken area in the Norwegian Sea can be further developed. The Njord A platform has been in production since 1997.

Facts:

Scaffolding used in the reinforcement process. (Photo: Ole-Andreas Nylund)

Njord A - the Njord field in the Norwegian Sea was developed with a floating steel platform, Njord A, with an integrated deck with a drilling and processing facility and living quarters. Njord A started production in September 1997.

The platform was designed for an original lifetime of 16 years – to 2013. The Petroleum Safety Authority subsequently approved the technical design lifetime to 2022.

Njord was a marginal field development with strong focus on low costs and rapid execution.

The area has a substantial resource potential which could provide a basis for production beyond 2013.

Njord Future – suring the structural reinforcement project, it became clear that, even with the reinforcements implemented offshore over the past year, the Njord A platform will not be robust enough to resume drilling activity in the summer of 2014. Nor will the platform be able to produce until 2022, which is the existing technical lifetime for the installation.

The Njord Future project has therefore been initiated to ensure a long-term solution for optimal resource utilisation in the Njord area.

There are considerable remaining resources in the area, and plans are now being laid to recover these resources, either using a modified Njord A platform or through construction of a new platform.

It is natural in this context to investigate possible cooperation solutions with other recent discoveries made in the area.