A large number of recent offshore natural gas discoveries in Israel have led to significant changes to the country’s fiscal terms, including the introduction of a windfall tax, and now a court decision could potentially add months to the current period of uncertainty surrounding authorization of gas exports, says a new report from research and consulting firm GlobalData.
According to the company’s latest report*, the new roadblock to natural gas exports, caused by the High Court of Justices decision to freeze the Israeli cabinet’s agreement on the revised export policy, will have serious implications for Israel’s upstream operators.
Following the report of the Tzemach Committee in September 2012, which suggested capping exports at 53% of proven and probable (2P) reserves, the Israeli cabinet made the decision in late June to set the cap at just 40% in order to ensure domestic supply for the next 25 years.
However, as many parties, including environmentalist groups, dispute the calculations on which such supply projections are based and wish to retain a higher percentage for domestic use, challenges have been brought against the policy on the basis that it was only decided upon by the cabinet, not the full Knesset (Israel’s parliament). The High Court of Justice took the decision on 1 August to freeze the Israeli cabinet’s decision, pending a Supreme Court hearing which will commence on 17 September.
Rabie Khellafi, GlobalData's Lead Analyst for the MENA region, says: This ruling is a blow both to the government and to operators, such as Noble Energy Inc., which have made significant discoveries in Israel’s offshore waters.
The analyst continues: Although some fields, such as Tamar, have already commenced production, others, including Leviathan the largest discovery in the area are still having development plans finalized. The export regulations will have a significant bearing on these plans and the deals which relate to them. For instance, Woodside Petroleum Ltd has agreed in principle to acquire a share in the Leviathan field, but the details of the final agreement depend on export plans.
In addition to these recent decisions, the Supreme Court could potentially rule that the Knesset will be responsible for approving any future decisions regarding the country’s natural gas export policy a move which Khellafi anticipates would cause further uncertainty within the sector.
Not only is Israel’s export policy not yet finalized, but if the court rules that final decisions on natural gas exports must lie with the Knesset, then further delays will ensue. Given the complications of projecting the country’s supply needs, renewed debate on the subject could be a lengthy process, and although export policy will probably be finalized within the next year, we can expect a considerably high level of uncertainty to remain within the sector for months to come, the analyst concludes.
*Israel Upstream Fiscal and Regulatory Report
.Technip was awarded by Shell Offshore Inc. (“Shell”) an important engineering, procurement and installation contract for the development of subsea infrastructure for the Stones field. This field is located in the Walker Ridge area in the US Gulf of Mexico, at a water depth of approximately 2,900 meters (9,500 feet). This development will host the deepest floating, production, storage and offloading (FPSO) unit in the world and will be Shell’s first FPSO in the Gulf of Mexico(1).
Technip will be in charge of installation of the subsea production system and Stones lateral gas pipeline(2), inclusive of associated project management, engineering and stalk fabrication.
Technip's operating center in Houston, Texas will perform the overall project management. The flowlines(3) and risers(4) will be welded at Technip’s spoolbase in Mobile, Alabama. The offshore installation is 
expected to be performed in the second half of 2014 by the Deep Blue (photo), Technip’s deepwater pipelay vessel.
David Dickson, Technip’s Senior Vice President, North America Region, has declared: “With greater depths come greater challenges for our clients and we are delighted to help Shell push back subsea frontiers by laying the deepest gas pipeline worldwide. With the award of this high-profile project, Technip confirms its subsea leadership and keeps differentiating itself through innovation to remain at the forefront of frontier projects.”
Rosneft and ExxonMobil continue to progress the LNG project proposed in the Russian Far East. The contractor selection 
process for design and engineering work has officially commenced.
In 2013-2014 Rosneft and ExxonMobil plan to complete design work, including selection of a liquefaction technology and identification of major equipment requirements, to perform engineering surveys, develop Front End Engineering and Design (FEED) and Russian Proyekt documentation for the LNG plant, hydro-technical marine facilities and a source gas pipeline, as well as perform EIA.
Special attention during the design phase will focus on minimizing environmental impact to the unique ecosystem of the Sakhalin island and encouraging development of local infrastructure. A joint team of experts from Rosneft and ExxonMobil will apply best practices from both companies to complete the project in the shortest possible timeframe.
Commenting on the progress of the LNG project in the Russian Far East, Rosneft President Igor Sechin said, “Rosneft’s offshore license areas hold massive hydrocarbon resource potential, most of which is natural gas. Given the fact that offshore fields are difficult to reach and are not connected to the national gas supply system, the most efficient way to monetize these resources is to liquefy the natural gas and sell the LNG in export markets.
“We are optimistic about prospects for LNG export liberalization in Russia in the near term and are pleased to announce that we have entered an important stage of the LNG project jointly with our strategic partner ExxonMobil.
“I would also point out that construction of the LNG plant and essential infrastructure will rely on the full resources of the Russian manufacturing and construction industries (primarily those based in the Far East) applying international best practices.”
Capacity of the LNG project to be located on Sakhalin Island in the Russian Far East is expected to be 5 million tons per year, subject to further expansion. The liquefaction plant, the launch of which is scheduled for 2018, will receive natural gas from Rosneft’s reserves in the Far East and other Sakhalin gas reserves.
.Apache Corporation (NYSE, Nasdaq: APA) says that the third well in the Bacchus Field in the United Kingdom sector of the North Sea has pushed field production past 17,600 barrels of oil per day. Apache has a 50 percent interest in the field.
The Bacchus B-1 development well, which commenced production in July, currently is producing 9,400 barrels of oil per day. Apache logged 2,057 feet net oil pay along a horizontal completion segment in high quality Jurassic-aged Fulmar sandstone in the field's western fault block. Oil from the Bacchus Field is produced through a subsea tie-back to Apache's Forties Alpha platform.
Following the recent success at Bacchus, Apache has extended its current Forties 3-D seismic survey area to cover other Jurassic development and exploration targets in Apache licenses in the Bacchus area. The seismic survey is expected to be completed in September.
Apache has brought three new fields — Bacchus, Maule and Tonto — on production in the Forties area since 2009. All three developments qualified under the United Kingdom government's small field allowance system, which provides economic incentives for operators to bring these discoveries into production.
"Utilizing existing infrastructure within the Forties Field area enables Apache to bring these smaller discoveries on production in a cost-effective manner for the benefit of all stakeholders," said James L. House, region vice president and managing director of Apache North Sea. "A little more than a year after first production, Bacchus has produced 3 million barrels of oil and has already paid out."
.
The Bureau of Safety and Environmental Enforcement (BSEE) and the Department of Energy (DOE) Office of Fossil Energy signed a Memorandum of Collaboration this week that will coordinate the ongoing efforts of the two agencies on offshore research and technological improvement projects. Through this collaboration, BSEE and DOE will continue to work together to ensure safe, sustainable offshore production of oil and natural gas.
“This Memorandum of Collaboration will ensure that the ongoing activities of our two agencies will continue to be appropriately coordinated,” said BSEE Director James Watson. “We will continue to prevent duplication and increase the effectiveness of our ability to create a regulatory environment that fosters the safe and responsible development of the Nation’s energy resources.”
“This Memorandum of Collaboration formalizes the interaction between our two agencies, and will help ensure that research and development executed by the Department of Energy is directly relevant to BSEE’s regulatory challenges.” said DOE Assistant Secretary Christopher Smith. “This is research that makes offshore oil and gas operations safer and environmentally sustainable while promoting our Nation’s energy security.”
The lead office within DOE that will work with BSEE is the Office of Fossil Energy, which supports research and development to ensure the Nation can continue to rely on clean, affordable energy from traditional fuel sources.
The agencies will continue to collaborate in support of three primary objectives: building safety through technological improvements; supporting research and development for offshore operations; and working together to support the implementation of recommendations arising from various investigations and studies related to Deepwater Horizon tragedy.
BSEE and the Office of Fossil Energy will engage in quarterly meetings to share near-term goals and track key milestones. Each year, the two agencies will prepare a joint progress report summarizing ongoing collaboration.
Click here for a copy of the Memorandum of Collaboration.
.T
he Caspian Sea region is one of the oldest oil-producing areas in the world and is quickly growing as a natural gas production hub.
The Caspian Sea region is one of the oldest oil-producing areas in the world and is an increasingly important source of global energy production. The area has significant oil and natural gas reserves from both offshore deposits in the Caspian Sea itself and onshore fields in the Caspian basin. Traditionally an oil-producing area, the Caspian area's importance as a natural gas producer is growing quickly.
This report analyzes oil and natural gas in the Caspian region, focusing primarily on the littoral (coastal) countries of the Caspian Sea (Russia, Azerbaijan, Kazakhstan, Turkmenistan, and Iran). A discussion ofUzbekistanis also included. While not a Caspian coastal state, a considerable amount of Uzbekistan's territory, along with its energy resources, lies in the geological Caspian basins.
Aside from Azerbaijan's oil production, the Caspian Sea largely was untapped until the collapse of the Soviet Union. With several newly independent countries gaining access to valuable hydrocarbon deposits, the different countries have taken diverging approaches to developing the energy resources of the area. At the same time, the lack of regional cooperation between the countries' governments and few export options for Caspian hydrocarbon resources have slowed the development of Caspian oil and natural gas resources.
The combination of foreign investment and rising energy prices allowed the coastal countries to shift from diverting oil extraction for local use to supplying both regional and world oil markets. The ability of countries to export greater volumes of Caspian crude oil and natural gas will depend on how quickly domestic energy demand rises in those countries, how quickly they can build additional export infrastructure to global markets, and whether expensive projects to develop Caspian resources can attract sufficient investment.
.
Eco (Atlantic) Oil & Gas Ltd. ("Eco Atlantic" or the "Company") (TSX-V: EOG, NSX: EOG) is pleased to announce that it has received final approval from Namibia's Ministry of Mines and Energy (the "Ministry") for the inclusion of all oil and gas rights on its Skeleton Coast License #31 which is a transition license that is both onshore Huab Basin and extends offshore Walvis Basin. The License, which the Company recently named "Daniel", covers Blocks 2114, 2013B and 2014B. The license originally covered only CBM and Shale rights but now will include all petroleum.
The Daniel Block has an offshore section extending into Walvis Basin that the Company has recently evaluated for oil prospectivity. Colin Kinley, Eco's Chief Operating Officer commented, "The offshore section of Daniel is near shore, however, it has good cover and is on trend with the slope and direction of the source rock, proven in the last two wells drilled by HRT in the basin. The drilling of the Toscanini well four decades ago on the beach section of this block, based on visible oil shows, seems to be consistent with our evaluation of the block. This oil presence was the basis for wild cat drilling of the Toscanini well, and our oil slick study with Fugro further defines oil presence in the basin and the prospectivity on the Daniel new offshore section of the block. We believe further work on the offshore section of this block will prove consistently prospective."
Gil Holzman, Chief Executive Officer of Eco Atlantic commented, "Eco continues with the focused evaluation of our offshore blocks in the Walvis Basin. We have carefully selected and negotiated the addition of the conventional oil and gas rights for the Daniel Block. The recent confirmation of source rock in both of HRT's wells in the basin is in agreement with our exploration science and definitely has increased focus on the Walvis Basin proven oil prospects. We are grateful for the Ministry's approval."
The Company further announces, based on its technical assessment, and in return for the conversion of License #31, the relinquishment of its CBM Exploration License #32, (Block 2418) onshore South East Namibia.
.Rowan Companies plc ("Rowan" or the "Company") (NYSE: RDC) announces that one of its subsidiaries has entered into a three-year contract with Cobalt International 
Energy, L.P. ("Cobalt") (NYSE: CIE) for the Rowan Reliance, one of Rowan's new ultra-deepwater drillships currently under construction at the Hyundai Heavy Industries Co. Ltd. ("HHI") shipyard in Ulsan, South Korea. The drillship is expected to operate in the U.S. Gulf of Mexico.
The Rowan Reliance is expected to be delivered from HHI at the end of October 2014. The contract is expected to commence late January 2015 following mobilization. The effective day rate for the work will be $602,000, including mobilization revenues, and adds $660 million in revenue backlog.
Matt Ralls, Rowan's Chief Executive Officer, stated, "We are very pleased to enter into this relationship with Cobalt. They have a very exciting growth story with a strong track record in ultra-deepwater exploration. We will complement their growth potential through our expansion into the ultra-deepwater drilling segment with the most advanced drillships in the industry. We are proud to have this opportunity to be part of the future success of this exciting company."
The Rowan Reliance is one of four ultra-deepwater drillships being constructed for Rowan by HHI. All four drillships are based on a GustoMSC P10,000 hull design, capable of drilling wells to depths of 40,000 feet in water depths up to 12,000 feet. The DP-3 compliant, dynamically positioned drillship will be equipped with retractable thrusters, two readily deployable seven-ram BOP systems,five mud pumps, dual mud systems and a maximum hookload capacity of 1,250 tons.
With the award of this contract for the Rowan Reliance, three of the Company's four ultra-deepwater drillships under construction at HHI are now under contract. The fourth remaining uncontracted drillship, the Rowan Relentless, is scheduled to be delivered from the shipyard at the end of March 2015.
.
As part of President Obama’s all-of-the-above energy strategy to continue to expand safe and responsible domestic energy production, the Department of the Interior’s Bureau of Ocean Energy Management on Wednesday held Western Gulf of Mexico Lease Sale 233, which offered 20.7 million acres and attracted $102,351,712 in high bids for 53 tracts covering 301,006 acres on the U.S. Outer Continental Shelf (OCS) offshore Texas. A total of 12 offshore energy companies submitted 61 bids.
The Western Gulf of Mexico Lease Sale builds on the first two auctions in the current Five Year Program – a 39-million-acre Central Gulf offering held in March, which netted almost $1.2 billion high bids and a 20-million-acre Western Gulf offering held last November that netted nearly $134 million.
“This offshore oil and gas lease sale supports continued growth in safe and responsible domestic oil and gas production,” said Acting Assistant Secretary for Land and Minerals Management and BOEM Director Tommy P. Beaudreau. “Over the past fourteen months, the offshore oil and gas industry has invested well over $3 billion in new federal leases in the Gulf of Mexico.”
Today’s sale offered all unleased and non-protected areas in the Western Gulf of Mexico planning area, including 3,864 tracts from nine to more than 250 miles off the coast, in depths ranging from 16 to more than 10,975 feet (five to 3,346 meters). BOEM estimates the lease sale could result in the production of 116 to 200 million barrels of oil and 538 to 938 billion cubic feet of natural gas.
Sale 233 was the third held under the Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012–2017 (Five Year Program), which makes available for exploration and development all of the offshore areas with the highest conventional resource potential that together include more than 75 percent of the Nation’s undiscovered, technically recoverable offshore oil and gas resources.
Domestic oil and gas production has grown each year the President has been in office, with domestic oil production currently higher than any time in two decades; natural gas production at its highest level ever; and renewable electricity generation from wind, solar, and geothermal sources having doubled. Combined with recent declines in oil consumption, foreign oil imports now account for less than 40 percent of the oil consumed in America – the lowest level since 1988.
Today’s highest bid on a single tract was $30,583,560 submitted by ConocoPhillips Company for Alaminos Canyon Block 475. ConocoPhilips Company also submitted the highest total amount in bonus bids, totaling $50,323,180 on 29 tracts.
BOEM received at least one bid within the three statute mile boundary area north of the continental shelf boundary between the United States and Mexico. Any bids submitted on blocks in the area will not be opened until on or before 30 days following the approval by the U.S. Congress of the agreement between the U.S. and Mexico or February 28, 2014, at which time the Secretary of the Interior may determine whether it is in the best interest of the United States either to open any such bids or to return the bid unopened.
BOEM established the terms for this sale after extensive environmental analysis, public comment and consideration of the best scientific information available. These terms include measures to protect the environment, such as stipulations requiring that operators protect biologically sensitive features and provide trained observers to monitor marine mammals and sea turtles to ensure compliance and restrict operations when conditions warrant.
The terms also continue a range of incentives to encourage diligent development and ensure a fair return to taxpayers, including an increased minimum bid for deepwater tracts, escalating rental rates and tiered durational terms with relatively short base periods followed by additional time under the same lease if the operator drills a well during the initial period.
Following the sale, each bid will now go through a strict evaluation process within BOEM to ensure the public receives fair market value before a lease is awarded. Sale statistics for Sale 233 are available at: http://www.boem.gov/Sale-233.
.As part of President Obama’s commitment to promoting safe and responsible offshore oil and gas development, Bureau of Safety and Environmental Enforcement (BSEE) Director James Watson has announced another key step to strengthen both human safety and environmental protection on the U.S. Outer Continental Shelf. The proposed rule, which will be published in the Federal Register tomorrow, implements best practices and updates regulations regarding production safety systems and equipment used to collect and treat oil and gas from offshore production facilities.
“Our guiding focus throughout the development of this proposed rule has been and will continue to be worker safety and protecting the marine and coastal ecosystems by helping to reduce the number of production incidents resulting in oil spills, injuries and fatalities,” said Director Watson. “The commonsense changes we are proposing, which will address issues such as production safety systems, subsurface safety devices and safety device testing, will help regulations keep pace with changing technologies that have enabled the industry to explore and develop resources in deeper waters. The rule also implements best practices currently being deployed by industry leaders as we continue to strive for safety at all levels, at all times.”
The proposed rule will revise 30 CFR 250 subpart H, Oil and Gas Production Safety Systems, to address recent technological advances. This section of the regulations has not had a major revision since it was first published in 1988. During that period, industry’s use of subsea trees (the assembly mounted on a well head used to control the flow of oil and gas) and other technologies have evolved or become more prevalent offshore. These devices and materials include foam firefighting systems; electronic-based emergency shutdown systems; subsea pumping, waterflooding, and gaslift; and new alloys and equipment for high temperature and high pressure wells. The proposed rule ensures that the regulations governing their use and maintenance are keeping pace with industry’s advancements and that they address these newer and emerging safety technologies.
The public is invited to submit comments starting tomorrow through October 21, 2013. Comments can be submitted by any of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov. In the entry titled Enter Keyword or ID, enter BSEE-2012-0005 then click search.
.The floating production sector has been especially active over the past several months. Ten production floaters have been ordered since March. They include a $3 
billion FPSO for Nigeria (a record price for an FPSO), two $1.8 billion FPSOs for Brazil, a $1.8 billion FPSO for the UK, a $1.3 billion production barge for the Congo and a $1.0 billion FPSO for the Gulf of Mexico.
MODEC's FPSO Cidade de Niteroi MV18
269 floating production units now in service or available —
This figure is 22% greater than five years ago, almost 80% higher than ten years back. FPSOs account for 61% of the existing systems. The balance is comprised of production semis, tension leg platforms, production spars, production barges and floating regasification/storage units. Thirteen units (12 FPSOs, 1 Semi) are off field and available for reuse – resulting in an overall utilization rate of 95.2%. Another 93 floating storage/offloading units (without production capability) are in service.
72 production floaters are on order —
Current order backlog consists of 40 FPSOs, 6 production semis, 5 TLPs, 4 spars, 1 barge, 4 FLNGs and 12 FSRUs. Delivery of the equipment will grow the production floater inventory by 27%. In the backlog are 46 units utilizing purpose-built hulls, 26 units based on converted tanker hulls and 1 unit being modified from an existing production semi Of the production floaters being built, 41 are owned by field operators, 31 are being supplied by leasing contractors. Brazil continues to dominate orders for production floaters – 23 units are being built for use offshore Brazil, 32% of the order backlog.
241 new floater projects are in the bidding or planning stage —
The number of future projects in the pipeline keeps growing. A year ago 233 projects were in the planning or bidding stage. Five years ago, the figure was 141 projects. Ten years back, 94 projects. According to Jim McCaul, head of IMA, "potential deepwater projects should grow significantly over the rest of the decade. Oil demand keeps growing, the futures market points to $90+ oil through the decade, deepwater drill contractors are running at full load and 90+ additional drillships/semis are scheduled for delivery over the next few years. These new drill units will increase deepwater drill capability by 30% and remove a bottleneck that has constrained E&D in deepwater."
But deepwater spending could be hitting headwinds —
Deepwater projects compete for a place in capital expenditure plans – and investment opportunities in tight oil and shale gas could cause some deepwater projects to slip from oil company capex budgets. This could be occurring now. According to McCaul, "maybe it is more than a coincidence that five major deepwater projects have been deferred over the past several months. Each project had its own reason for deferral. But five in such a short period sends warning signals to everyone in this sector."
International Maritime Associates (IMA) is a firm of business consultants specializing in market analysis and strategic planning for companies in the marine and offshore sectors. We provide the front-end research needed to size the available market, analyze customer requirements, benchmark market position, identify new business opportunities, evaluate market positioning options and assess potential acquisitions or strategic alliances. Since formation in 1973, IMA has performed over 350 consulting assignments for clients in more than 40 countries.
Petrobras has confirmed the presence of oil in well 3-SPS-101 (3-BRSA-1179-SPS), in the Carioca Discovery Evaluation Plan area, block BM-S-9, Santos Basin pre-salt. The well, informally known as Iguaçu Mirim, is located 303 km off the coast of the state of São Paulo, 34 km south of the discovery well (1-SPS-50 - Carioca) and 9 km south of the Iguaçu well (4-BRSA-709-SPS), at a water depth of 2,158m.
This new discovery was confirmed through oil samples of approximately 20° API, taken via cable test from pre-salt carbonate reservoirs starting at a depth of 4,850 meters.
The consortium of BM-S-9 is operated by Petrobras (45%) in partnership with BG E&P Brasil (30%) and Repsol Sinopec Brasil (25%). The deadline for the Declaration of Commerciality is December 31, 2013.
Please Click Here to see the map.
.
Statoil has made a third discovery of crude oil in the Flemish Pass Basin, offshore Newfoundland.
“The success of Bay du Nord is the result of an ambitious and targeted drilling campaign in the Flemish Pass Basin,” says Statoil Exploration executive vice president Tim Dodson. “This discovery is very encouraging.” Dodson explains that as the volumes of both the Bay du Nord and Harpoon wells continue to be evaluated, Statoil is developing a greater understanding of the geology and potential of the basin.
“The Flemish Pass Basin is a strategic part of Statoil’s global exploration portfolio. We are now planning to return to the area for further appraisal drilling in the future,” says Dodson.
“The success of Bay du Nord is the result of an ambitious and targeted drilling campaign in the Flemish Pass Basin,” says Statoil Exploration executive vice president Tim Dodson. “This discovery is very encouraging.” Dodson explains that as the volumes of both the Bay du Nord and Harpoon wells continue to be evaluated, Statoil is developing a greater understanding of the geology and potential of the basin.
“The Flemish Pass Basin is a strategic part of Statoil’s global exploration portfolio. We are now planning to return to the area for further appraisal drilling in the future,” says Dodson.
The Bay du Nord and Harpoon wells were drilled by the semi-submersible rig West Aquarius, both in approximately 1,100 metres of water. Bay du Nord is located about 20 kilometres south of Statoil’s Mizzen discovery. The Mizzen discovery, announced in 2010, is estimated to hold between 100-200 million barrels of oil. Statoil is the operator of Bay du Nord and Harpoon with a 65% interest. Husky Energy has a 35% interest.
.
Operator Statoil has together with PL479 partners made a gas/condensate discovery in the Smørbukk North prospect at Haltenbanken in the Norwegian Sea.
Exploration well 6506/9-3, drilled by the drilling rig Transocean Leader, has proven a 40-metre gas/condensate column in a down-to situation in the Garn formation of mid-Jurassic age.
In addition a thin gas/condensate column was proven deeper in the mid-Jurassic Ile formation. The reservoir properties of the Garn formation are good, while somewhat poorer than expected in the Ile formation.
The preliminary estimated volume of the discovery is in the range of 25-47 million barrels of recoverable oil equivalent (o.e.).
"We are very pleased with having proven the new resources," says Gro G. Haatvedt, senior vice president exploration Norway in Statoil.
"The three discoveries comprising the Åsgard field were all made in the 1980s. Making a new discovery in the area 30 years later is encouraging and proves the exciting remaining potential on the NCS."
Smørbukk North is a typical example of timely near-field exploration, which is an important element in Statoil's sharpened exploration strategy for the NCS.
"Being located directly north of the Åsgard field, the Smørbukk North discovery could be developed quickly and efficiently through a tie-in to existing infrastructure, providing fast resources and potentially extending the production life of the Åsgard production facilities," says Astrid Jørgenvåg, vice president operations at Åsgard.
Smørbukk North was a high temperature well (HT), so special attention was given to ensuring safe drilling operations.
"Smørbukk North was a demanding well to drill, but due to thorough planning and extra HSE focus, the operations have so far been carried out without serious incidents and are currently 21 days ahead of schedule," says Haatvedt.
Exploration well 6506/9-3 is situated in PL479 in the Norwegian Sea. Statoil is operator with an interest of 40.95%. The partners are ENI Norge AS 19.6%, Petoro AS 14.95%, ExxonMobil Exploration & Production Norway AS 14.7%, and Total E&P Norge AS 9.8%.
For further details on the results of exploration well 6506/9-3, please see the press release issued by the Norwegian Petroleum Directorate (NPD)
.The Bureau of Safety and Environmental Enforcement (BSEE), U.S. Coast Guard, and Walter Oil & Gas Corporation (Walter), through the Unified Command, continue to 
oversee and coordinate response efforts to secure the South Timbalier 220 natural gas Well A-3. Safety of personnel and protection of the environment remain the top priorities.
All debris is now removed from the wellhead giving crews vertical access to the well, removal was done from the derrick barge “Performance”.
BSEE approved plans to send a camera and logging tools down the wellbore and is conducting visual observation along with Unified Command. Observations will be used to advance well intervention plans. No gas releases are reported from fixed wireless detectors placed some 30 feet from the top of the well or detection devices carried by all onsite personnel.
Drilling on the relief well is underway using the Rowan EXL-3 jack-up rig, contracted by Walter. Drilling is expected to continue through early September. Many factors can affect the expected schedule including weather and the intricate work of locating the target well bore at the end of the drilling process. A relief well is drilled to intercept the target well. Once intercepted, drilling mud, followed by cement will be pumped into the well to secure it.
All available options to safely secure the natural gas well remain under consideration. Work is moving forward on all approaches.
From visual observation, a sheen is no longer present in the area of the well. The Coast Guard continues to maintain a 500-meter safety zone around the site. Firefighting and other marine vessels remain onsite with personnel from Walter, Hercules, and other professional engineering contractors, and relevant federal agencies. BSEE's investigation into the cause of the loss of well control continues in coordination with the Coast Guard.
Additional updates will be issued as information becomes available. Media inquiries and requests for additional information should be directed to. 504-736-2595.
BACKGROUND: Walter experienced a loss of control of Well A-3 at approximately 8:45a.m. July 23 on an unmanned platform at South Timbalier Block 220 while doing completion work on the sidetrack well to prepare the well for production. The operator reported the safe evacuation of 44 personnel from the Hercules 265 jack-up rig. Coast Guard confirmed that the leaking natural gas ignited at 10:45 p.m. CDT July 23. BSEE confirmed July 25 that the well flow subsided after a natural bridging process and the fire was suppressed.
.
Ascent Resources plc, the AIM listed European oil and gas exploration and production company, today announces that it has agreed to dispose of its full interests in the Netherlands Exploration Licenses Terschelling-Noord and M10a & M11 to Tulip Oil Netherlands B.V. for a total cash consideration of up to €450,000, before selling expenses, once the consents for the transfer of the Licenses become irrevocable. These licenses did not form part of the core asset base on which the board has decided to focus.
The agreement grants Ascent the right to re-purchase from Tulip Oil a 10% interest in each of the Licenses once Tulip Oil has made a final investment decision with respect to the commercial development of the Terschelling-Noord Field.
The disposal enables Ascent to recover a proportion of its technical appraisal costs incurred during the period it held the Licenses.
Len Reece, Ascent's Chief Executive Officer, commented: "This transaction is in accordance with our corporate strategy of disposing of non-core assets. It provides additional cash for the Company in the short term and allows Ascent to focus our efforts and resources on our core Petišovci project in Slovenia."
.
Offshore Source keeps you updated with relevant information concerning the Offshore Energy Sector.
Any views or opinions represented on this website belong solely to the author and do not represent those of the people, institutions or organizations that Offshore Source or collaborators may or may not have been associated with in a professional or personal capacity, unless explicitly stated.
