TransMontaigne Partners L.P. (NYSE:TLP) has announced commercial operations are underway for phase one at the 185-acre Battleground Oil Specialty Terminal Company, LLC (BOSTCO) on the Houston Ship Channel. Approximately 20 of the 51 storage tanks being built during phase one construction are being placed into service this month, and the remaining tanks will come online during the next six months. A two-berth ship dock and 12 barge berths are also scheduled to be in service this month.



A joint venture of TLP (which owns a 42.5 percent interest in the facility) and Kinder Morgan Energy Partners, L.P. (NYSE: KMP), the approximately $485 million BOSTCO oil terminal at mile marker 43 on the Houston Ship Channel is fully subscribed for a total capacity of 7.1 million barrels and is able to handle ultra low sulfur diesel, residual fuels and other black oil terminal services.


Phase two of construction at BOSTCO is underway and involves the construction of an additional six, 150,000-barrel, ultra low sulfur diesel tanks, additional pipeline connectivity and high-speed loading at a rate of 25,000 barrels per hour. BOSTCO expects phase two to begin service in the fourth quarter of 2014.



"We are pleased to announce the commencement of operations of the BOSTCO facility, which provides the market with a unique, deepwater terminaling solution that provides high speed loading and improved barge and ship access to the Texas Gulf Coast for the export and import of various refined products," said Charles Dunlap, Chief Executive Officer of TLP’s general partner.



The BOSTCO project is employing approximately 750 local contractors during construction and has hired about 75 full-time employees to operate the facility.



Statoil (OSE:STL, NYSE:STO) Canada and co-venturer Husky Energy have announced that the first Bay du Nord exploration well has discovered between 300 and 600 million barrels of oil recoverable.  

The Bay du Nord discovery, located approximately 500 kilometers northeast of St. John's, Newfoundland and Labrador, Canada, was announced in August. A sidetrack well has been completed this week and confirms a high impact discovery. Additional prospective resources have been identified which require further delineation.

The Bay du Nord discovery is Statoil's third discovery in the Flemish Pass Basin. The Mizzen discovery is estimated to hold a total of 100-200 million barrels of oil recoverable. The Harpoon discovery, announced in June, is still under evaluation and volumes cannot be confirmed at this stage.

The Bay du Nord well encountered light oil of 34 API and excellent Jurassic reservoirs with high porosity and high permeability.

"It is exciting that Statoil is opening a new basin offshore Newfoundland," says Tim Dodson, executive vice president of Statoil Exploration. "This brings us one step closer to becoming a producing operator in the area."

"With only a few wells drilled in a large licensed area, totaling about 8,500 square kilometers, more work is required," adds Dodson. "This will involve new seismic as well as additional exploration and appraisal drilling to confirm these estimates before the partnership can decide on an optimal development solution in this frontier basin."

The successful drilling results from the Flemish Pass Basin demonstrate how Statoil's exploration strategy of early access at scale and focus on high-impact opportunities is paying off. As an early player in the area, Statoil has confirmed its understanding of the basin and has opened a new oil play offshore Canada.  The Flemish Pass has the potential to become a core producing area for Statoil post-2020.

All three discoveries are in approximately 1,100 meters of water. Mizzen was drilled by the semi-submersible rig Henry Goodrich (2009). The Bay du Nord and Harpoon wells were drilled by the semi-submersible rig West Aquarius (2013).

Statoil is the operator of Mizzen, Harpoon and Bay du Nord with a 65% interest. Husky Energy has a 35% interest.

(High impact discovery = > 100 mmboe net to Statoil or > 250 mmboe in total)

Shell and Baker Hughes has announced a software license and joint development agreement to produce a high-end platform for geological and reservoir modeling. The new platform will bring enhanced evaluation and visualization capabilities to Shell allowing geoscience and petroleum engineering experts to better plan and manage the extraction of oil and gas resources, realizing their full potential.

“High-quality modeling of complex reservoirs is a major factor in creating additional value in our industry,” said Arjen Dorland, Shell’s EVP for Technical and Competitive IT. “Today’s announcement underlines Shell’s commitment to developing innovative technologies that give us and our partners a competitive edge.”

The system will be optimized for resource modeling and production in tight/shale gas and liquids rich shale reservoirs, and is based on the Baker Hughes JewelEarth™ software platform, which has a strong track record of delivering integrated, data-driven workflows for optimizing these types of plays.

The world is now thought to have around 230 years of recoverable gas resources at current production levels – of which roughly half is tight gas, shale gas, and coalbed methane. Shell is producing these gas resources in locations including the US, China and Australia.

The new platform will complement Shell’s existing applications, including GeoSigns, Shell’s proprietary software used to visualize and interpret seismic data, and will form part of an integrated working environment for Shell’s exploration and modeling experts.

“The JewelEarthTM platform can handle multiple solutions – from basin to wellbore scale – using one generic data source,” said Mario Ruscev, Chief Technology Officer at Baker Hughes. “This capability will provide an innovative modeling and optimization platform for the fast-growing Shell user community”

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

Shell and its partners have begun production from the second development phase of the Parque das Conchas (BC-10) project, located off Brazil’s south-east coast. The BC-10 project (Shell share 50%, Petrobras 35%, ONGC 15%) is comprised of several subsea fields which are tied back to a floating production, storage and offloading (FPSO) vessel, named the Espírito Santo.

In 2009 the first phase of the project began production, when the Abalone and Ostra fields were connected, along with the Argonauta B-West reservoir. The peak production of the first phase was more than 90,000 barrels of oil equivalent (boe) in 2010, and is currently producing some 35,000 boe per day.  Phase 2 connected a fourth reservoir to the vessel, the Argonauta O-North. At its peak, Phase 2 is expected to produce approximately 35,000 boe per day.



“Boosting production at BC-10 with the completion of phase two is another great example of our successful project development, delivery and execution capabilities,” said John Hollowell, Executive Vice President for Deep Water, Shell Upstream Americas. “It is a great day for Shell in Brazil.”



Building on what was already a successful proving ground for technology innovation, a 4-D Life of Field Seismic monitoring system was installed as part of Phase 2 subsea development. This technology, consisting of a network of seismic sensors installed throughout the field on the seabed, allows us to more effectively and efficiently monitor the reservoir. This is the deepest installation of its kind on a full-field scale in the world (approximately 1800m or 6000 feet).


Expecting to maximize the production life of BC-10 even further, Shell and its partners recently announced in July the decision to move forward with the project’s third development phase, which will include the installation of subsea-infrastructure at the Massa and Argonauta O-South reservoirs. Once online, Phase 3 of the BC-10 project is expected to reach a peak production of 28,000 boe.

Discovered Resources for Rio Grande Area Increased to 50 - 100 MMBoe

Noble Energy, Inc. (NYSE: NBL) has announced a discovery at the Troubadour exploration prospect in the Deepwater Gulf of Mexico.  The well, located in Noble Energy's Big Bend/Troubadour "Rio Grande" area, is located in 7,273 feet of water on Mississippi Canyon Block 699 and was drilled to a total depth of 19,510 feet.  Reservoir and fluid measurement logs identified approximately 50 feet of net natural gas pay in a high-quality Miocene reservoir. 

Image Credit: Noble Energy Inc.

Susan Cunningham, Noble Energy's Senior Vice President, Gulf of Mexico, West Africa and Frontier Ventures, commented, "The discovery at Troubadour follows on our earlier exploration success at Big Bend, which combine to provide another significant development opportunity for our Gulf of Mexico business.  Results from the well have provided critical new information that indicates a greater than previously predicted oil recovery in the Rio Grande complex.  Discovered gross resources⁽¹⁾ in this area are now estimated at between 50 and 100 million barrels of oil equivalent, with 75 percent representing oil volumes.  We are moving forward our development planning as subsea tiebacks to an existing host facility.  Initial project sanction is targeted by the end of this year and first production is planned toward the end of 2015." 

The Troubadour discovery well is being temporarily abandoned for future development.  Following completion of operations at Troubadour, Noble Energy plans to move the drilling rig to the Dantzler prospect on Mississippi Canyon 738/782.  Dantzler is operated by Noble Energy with a 65 percent participating interest and is targeting a resource range⁽¹⁾ of between 50 and 220 million barrels of oil equivalent gross.  Results from the exploration well are anticipated by the end of 2013.

Noble Energy operates Big Bend with a 54 percent participating interest and Troubadour with a 60 percent interest.  Other interest owners at Big Bend include Red Willow Offshore, LLC with 15.4 percent, Houston Energy Deepwater Ventures V, LLC with 10.6 percent and W&T Energy VI, LLC (a wholly owned subsidiary of W&T Offshore Inc.) with 20 percent.  W&T Energy VI, LLC and Deep Gulf Energy II, LLC participate in Troubadour with 20 percent each.

(1)  Range of resource estimate based on 75^th and 25^th percentile probabilities

Business Monitor has just released its latest findings on Mexico’s oil & gas sector in its newly-published Mexico Oil & Gas Report.

Never before has Mexican energy sector reform been both more critical and more attainable. Business Monitor note that without reform and a resulting uptick in foreign investment, the country is set to switch from being one of the largest oil exporters in the world to a net importer by the latter part of its 10-year forecast period. However, while Mexico's ruling Partido Revolucionario Institucional has recently introduced a proposal to remove long-standing limits on private sector involvement in upstream activity - a key first step - Business Monitor believe that whether there is substantial interest from the major international oil companies will be largely determined by the wording of secondary legislation and specific contractual details. As such, although the Mexico Oil & Gas Report highlights substantial upside risks, for now Business Monitor retains its relatively pessimistic forecasts for the sector.

The report forecasts a steady decline in both Mexican proven oil reserves and production over the next decade, with the country likely to become a net importer rather than one of the world's largest net exporters - as is the case at the moment - by the end of its forecast period. This is on the back of several years of declining production, combined with the recognition that it will take a significant amount of time for any new production to come online. Furthermore, the country's most productive fields, especially Cantarell, are maturing at a rapid rate, resulting in a steady trend of reserve depletion. Business Monitor forecast 2013 oil production of 2.94mn barrels per day (b/d), falling to 2.82mn b/d in 2017. Production will end the forecast period in 2022 at 2.59mn b/d.

Business Monitor’s bearish view of Mexican oil production is reinforced by several interconnected fundamentals, including Pemex's relative inexperience in deepwater drilling as well as high tax and debt burdens. Also, the current inability for the company to work with foreign partners also prevents it from spreading capital risk, while also not being able to capitalize on foreign expertise and technology.

The report remarks that Mexican pipeline imports of natural gas have grown almost in parallel with the US natural gas production boom over the last few years. Importantly, because the imported gas is priced at the US Henry Hub benchmark, imports remain cheap despite surging demand growth. These price dynamics have a reinforcing effect, and therefore will support future demand growth. As such, Business Monitor expect this trend to remain in place for the foreseeable future - with its associated negative implications for Mexican domestic natural gas production, underpinning its forecast for Mexican gas production to grow at a modest 1% per annum for the long-term.

The stakes for energy sector liberalisation have therefore never been higher. At the time of writing the report, the ruling Partido Revolucionario Institucional (PRI) has put forward a reform proposal which would amend the constitution to allow private sector actors to play a more significant role in upstream activity. While an important step though, there is some risk that the government party's proposed reform may still not be sufficient to reverse the country's declining oil production as it centres on a profit-sharing model - less attractive to international oil companies (IOCs) than concessions or production-sharing frameworks.

Indeed, given the PRI's more moderate proposal, Business Monitor believe the extent to which Mexico is able to boost investment will be largely dependent on whether forthcoming secondary legislation is favourably written and how lucrative the contract terms on offer are - something that will not become apparent for several more quarters at least. As such, while Business Monitor sees some increased upside potential, for now it maintain its pessimistic forecasts.

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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.

Chevron Corporation (NYSE: CVX) has announced that its Australian subsidiaries have signed binding long-term Sales and Purchase Agreements (SPAs) with Tohoku Electric Power Company, Inc. (Tohoku) to supply liquefied natural gas (LNG) from the Chevron-operated Wheatstone Project in Western Australia.

Under the agreements, Chevron subsidiaries, together with subsidiaries of Apache Energy and Kuwait Foreign Petroleum Exploration Company, will supply Tohoku with 0.9 million tons per annum of LNG for up to 20 years.

Joe Geagea, president, Chevron Gas and Midstream, said, "These agreements with Tohoku create a new partnership between our companies and demonstrate the benefits of buyers and sellers working together to ensure supply is brought to the market to meet growing LNG demand."

Roy Krzywosinski, managing director, Chevron Australia, said, "We welcome the agreements with Tohoku, which mean that 85 percent of Chevron's equity LNG from Wheatstone is now committed to customers in Asia on a long-term basis.  These agreements, combined with our ongoing exploration success, demonstrate that our Wheatstone and Gorgon projects in Australian are well-placed to meet the growing demand for natural gas in the Asia-Pacific region."

The Wheatstone Project is located at Ashburton North, 7.5 miles (12 kilometers) west of Onslow in Western Australia. The project will consist of two LNG trains with a combined capacity of 8.9 million tons per annum and a domestic gas plant.

The Wheatstone Project is a joint venture between Australian subsidiaries of Chevron (64.14 percent), Apache Energy (13 percent), Kuwait Foreign Petroleum Exploration Company (7 percent), Shell (6.4 per cent), and Kyushu Electric Power Company, Inc. (1.46 percent), together with PE Wheatstone Pty Ltd. (8 percent).

Chevron also holds an 80.17 percent equity interest in the Wheatstone and Iago fields that provide 80 percent of the feed gas to the Wheatstone Project. The participants in the fields are PE Wheatstone Pty Ltd. (10 percent) as well as Australian subsidiaries of Shell (8 percent) and Kyushu Electric Power Company, Inc. (1.83 percent).

Subsea 7 S.A. (Oslo Børs: SUBC) today announced a contract award by Stone Energy valued in excess of US$70 million for the development of the Cardona field in the U.S. Gulf of Mexico.

The contract scope includes engineering, procurement, installation and commissioning of flowlines, risers, pipeline structures, and a gas lift umbilical.

Project management and engineering work will commence immediately at Subsea 7’s offices in Houston. Offshore operations are due to commence in the third quarter 2014, with stalking of the risers and flowlines and welding being performed at Subsea 7’s Port Isabel spoolbase.

Ian Cobban, Subsea 7’s Vice President for the Gulf of Mexico, commented that “We are pleased to be awarded this contract and look forward to working collaboratively with Stone Energy. This is an important project for both Stone Energy and Subsea 7, and we look forward to delivering the project in a safe and timely manner, and to building a strong relationship.”

A standard program template for UK offshore decommissioning projects has been credited with heralding a step-change for the industry after being formally endorsed by the UK regulators and successfully trialled by three international operators for different types of asset.

Decommissioning industry body Decom North Sea (DNS) developed the template in partnership with the Department of Energy and Climate Change (DECC).  The new template will help streamline and standardize the format for decommissioning programmes throughout the UKCS whilst still fully satisfying regulatory requirements.

The template is already allowing industry to compile decommissioning programs more quickly and easily by presenting information in a consistent and standardised format, reducing time spent on redrafts, improving efficiency and reducing costs.

First to trial the template was BP with the Schiehallion Decommissioning Programme, whilst CNRI is currently trialling it to set out its plans for the Murchison Platform (Photo). Perenco is also using the template for the Thames Project. All of the operators had positive feedback on the template, noting significant changes and a reduced number of drafts.

An initial draft of the workgroup’s template was circulated to government departments, industry and other stakeholders via DNS members, Oil & Gas UK and DECC. More than 50 responses were received and the comments were collated into a final draft document by DECC and DNS, which was reviewed again by the workgroup before being finalised.

The resulting template allows future decommissioning programs to be prepared and assessed in a more consistent fashion. Operators are being encouraged to trial it during 2013 and feedback from those users will be used to further improve the template.  It is hoped that the template’s use for non-derogation cases will become mandatory in 2014. A streamlined template for derogation cases is also under development.

DNS Chief Executive Brian Nixon said: “We are delighted to have been instrumental in such a major project and the rapid uptake of the template by operators shows very clearly that the approach taken by DNS and partners was a success. We are now building on the collaborative working model to tackle other key industry challenges.

“The members of the working group gave generously of their time to design and deliver the template and this has been an excellent early example of DNS members working collaboratively with Government to deliver a substantial piece of work already showing significant demonstrable benefits. Ultimately, it will reduce costs to the public purse whilst maintaining the integrity and transparency of the decommissioning process.”

A DECC spokesman said: “This is a great example of DECC and industry working together on a project with the potential to achieve considerable savings and efficiencies to operators, the regulator, consultants and contractors.’’

Alistair Corbett, BP’s Decommissioning Projects Manager, said: “The Schiehallion Decommissioning Program was approved in June by DECC, using the new Standard Decommissioning Programme Template. Though it was only officially issued for use in January 2013, we were given permission in December 2012 to trial it.

“That meant seven months from initiation to approval, compared to up to three years in the case of Miller – also the document ended up only 42 pages in length. This equates to a major saving in man-hours and project delivery schedule and demonstrates the success of a joint oil industry and Governmental co-operation project.”

Roy Aspden, Decommissioning Projects Manager, CNRI, said:  “We are delighted to have been part of the team responsible for producing the standard decommissioning template as well as pioneering its use. 

“The template’s format has enabled us to set out our proposals for the Murchison platform clearly and concisely, making the decommissioning programme easily accessible to our stakeholders and significantly reducing the reading burden without compromising essential information.  It has also provided a helpful focus for CNRI’s meetings with the regulator during the development of the program.

“Overall, the initiative to develop the new template is a great example of what can be achieved through teamwork.  It represents a step-change in the simplification and standardisation of data vital to those considering and commenting upon decommissioning programs and augurs well for the future development of the decommissioning capability and cooperation across the range of interested parties.”

Perenco’s Operations Manager Keith Tucker, added: “Perenco's experience of a recent submission of a draft decommissioning program on the standard template has proven very successful. It demonstrates a significant step change improvement on the previous process, achieved jointly by DNS and DECC collaboration.”

It is hoped that, in time, the template could also be adopted for use in other European countries (albeit with some minor alterations perhaps being needed), helping operators and contractors alike to standardise their efforts across the North Sea.

Building on the success, DNS has established a projects sub-committee looking to move forward similar projects. They are currently canvassing ideas from the membership.

The forum is also continuing its focus on synergy and knowledge share at its annual Offshore Decommissioning Conference, in partnership with Oil & Gas UK, at St. Andrews from 1-3 October. With a number of panel discussions and networking opportunities, the event will focus on collaboration and promoting knowledge share and best practices among decommissioning operators and supply chain members. 

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.

Petrobras announces that, in August, oil output (oil plus natural gas liquids - NGL) from all the company's fields in Brazil averaged 1,908,000 barrels per day (bpd). This volume is 1.1% higher than the average output of the previous month (1,888,000 bpd). Including the share operated by the company for its partners, oil output exclusively in Brazil reached 1,971,000 bpd, indicating a 1.3% rise from July.



This positive result is due to the resumption of operations on platforms undergoing scheduled maintenance stoppages in July (P-40 in Marlim Sul, P-20 in Marlim, PPM-1 in Pampo and FPSO-RJ in Espadarte) and the startup of wells on platforms P-54 and FPSO-Piranema. According to the schedule, production was halted on platforms P-26 and P-35 (both in Marlim) in August to comply with the scheduled maintenance shutdown program. 



In August, Petrobras' total output (oil and natural gas) in Brazil averaged 2,294,000 barrels of oil equivalent (boed), 0.5% higher than output in July. Including the share operated by Petrobras for partners, total output volume in August was 2,401,000 boed, 0.6% up on the July output.

Operations to connect platform P-63, the first production unit in Papa-Terra field, to mooring lines, are currently in the completion phase. This platform will start up operations on October 23.



The construction of platform P-55 has been completed and, on September 17, the inclination tests were initiated. By the first week of October, it should move to the Campos Basin' Roncador Field.

Added to the company's August output abroad, total oil and natural gas volume averaged 2,499,000 boe/d, 0.3% up on total output in July.



Natural Gas Production



In August, non-liquefied natural gas output from the company's fields in Brazil was 61.378 million m³ per day. Total natural gas output, including the share operated by the company for its partners, was 68.336 million m³ per day, close to output levels in July. 


International Production

In August, total extraction of oil and natural gas abroad was 205,698 boed, 1.4% down on July, due to an adjustment in the calculation of oil from Akpo field, Nigeria.

Statoil has together with partners in PL128 made an oil discovery in the Svale North prospect in the Norwegian Sea, approximately nine kilometers northeast of the Norne field.

Exploration well 6608/10-15, drilled by the Songa Trym drilling rig (Photo), has proven a 45 meter oil column in the Åre formation and a 45 meter oil column in the Melke formation. The reservoir properties were as expected in both targets.

The preliminary estimated volume of the discovery is in the range of 6 to 19 million barrels of recoverable oil. It will be considered if the discovery can be tied to the Norne field.

"We are very pleased with the discovery," says Gro G. Haatvedt, Statoil senior vice president for Exploration Norway.

"With last month's announcement of the Smørbukk North discovery near Åsgard, this is the second discovery in the Norwegian Sea in three weeks. Timely near-field exploration provides valuable resources to Statoil and the discoveries show that there is still exciting potential in the Norwegian Sea."

"We work continuously on increasing the recovery and extending the life of the Norne field. The Svale Nord discovery confirms the prospectivity and Statoil's exploration success in the area. The discovery could lead to a further extension of the Norne field production life," says Hans Jakob Hegge, senior vice president for the operations north cluster in Statoil.

Exploration well 6608/10-15 is situated in PL128 in the Norwegian Sea. Statoil is operator with an interest of 63.95455%. The partners are Petoro AS (24.54546%) and Eni Norge AS (11.5%).

Statoil has started the build-up of its Aberdeen operating organization and reported at SPE Offshore Europe 2013 that the company and its partners are on track with the Mariner field development project.

The Mariner heavy oil field was discovered in 1981. Statoil entered the license as operator in 2007 with the aim of finally unlocking the resources.

 The company and its partners took the final investment decision in December 2012 and the UK government's Department of Energy and Climate Change announced their approval of the field development plan in February 2013.

"This is the largest new offshore field development in the UK in over a decade. It has been 30 years in the making, and now we are on track developing the field and preparing for 30 years of production," says Lars Christian Bacher, Statoil's executive vice president for Development and Production International.

Statoil expects to start production from Mariner in 2017. The average production is estimated at around 55,000 barrels of oil per day over the plateau period from 2017 to 2020.   Expected recoverable oil volumes are estimated to more than 250 million barrels.

 Statoil has started the build-up of its local organization in Aberdeen and is planning to have a new operations center in place by 2016.

"The project will lead to substantial job creation in the region with more than 700 long-term, full-time positions," Bacher says.

Statoil aims to recruit most of these positions locally, and is now launching a branding campaign in Aberdeen to support recruitment efforts.

"We started the year with one employee in Aberdeen and expect to have a 75-person strong organization by year end," Bacher says.

Statoil has utilized its extensive heavy oil experience from Norway, Brazil and Canada in its efforts to find a viable development solution for the Mariner heavy oil field.

The field will be developed with a production, drilling and quarters platform based on a steel jacket with 50 active well slots, and a floating storage unit of 850,000 barrels capacity. In addition a jack-up drilling rig will be used to assist the drilling for the first four to five years.

The UK and global supplier industry will play a central role in the development of the Mariner project. The majority of facility contracts have been awarded, in addition to the contracts for drilling from the fixed platform and the jack-up rig.

Contracts within operations and maintenance, drilling and well services, and business support will be tendered from 2013 to 2016.

The majority of suppliers within these areas will be based in the UK, generating many long-term, UK-based jobs with contractors. Statoil has established an Aberdeen procurement organization, and is actively informing UK suppliers of its plans and activities.

Following the award of the major facilities contracts Statoil is currently ramping up activities at the construction yards. Offshore installation of the platform jacket is scheduled for mid-2015, followed by topsides during 2016.

Statoil is also the operator for the Bressay heavy oil field on the UK continental shelf where expected recoverable oil volume is 200-300 million barrels.

"We have chosen a stepwise approach starting with Mariner to ensure experience transfer and learning before we move forward with Bressay. The Bressay field's reservoir characteristics make it even more challenging than Mariner. Our focus is now on making the required preparations for project decision and execution, including necessary preparations for authority approval," says Bacher.

Statoil and its partners have selected a development concept with clear similarities to the Mariner project, but with some differences due to subsurface characteristics. The Mariner contracts include options for Bressay, and execution planning is in progress.

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.