With Brazil’s  first exclusive pre-salt bidding round underway this month for a single block containing the Libra field, and massive potential identified within the country’s offshore pre-salt layer, bidding between several consortia is expected to push the state’s  take significantly higher than that which would result from a Concession Contract, says research and consulting firm GlobalData.

According to the company’s latest report*, Brazilian authorities consider the exploratory risk in pre-salt areas to be relatively low, and legislation was passed to govern upstream oil and gas activities within an area designated as the pre-salt polygon using Production Sharing Contracts (PSCs), instead of the traditional Concession Contract regime.

This form of contract ensures a higher government take from production projects and is being offered in the first bidding round for Libra, which is estimated to hold reserves of between eight and 10 bbl (billion barrels). State take from this and other fields within the area is now expected to be near 75%, which would represent a base state profit oil share of around 50%.

As well as the government receiving a share of production, higher royalties equal to the value of 15% of gross oil and tax production are payable, compared to a maximum of 10% under Concession Contracts. Meanwhile, a signature bonus for Libra, set at BRL15 ($6.3 billion), is also payable, but the Special Participation tax is not applicable.

Adrian Lara, GlobalData’s  Lead Analyst covering Upstream Oil & Gas, says: “While the effective production-sharing terms for the Libra block will not be known until the conclusion of the first pre-salt bidding round, the nature and caliber of companies taking part suggests to us that the competition will occur between three or four bidding consortia, despite the conspicuous absence of US oil giants.

However, beyond the initial pre-salt licensing rounds and into the medium-term, we are expecting further pre-salt licensing to progress at a relatively slow pace, with blocks only being offered once discoveries or prospects have been identified by Petrobras, Lara continues. “By clearly identifying potential before offering acreage, the risk for prospective investors will be lowered and the state will be able to secure a higher stake.”

In addition to the pre-salt bidding round taking place this month, November will also see the start of Brazil’s 12th Concession round, which will offer blocks in frontier and mature onshore basins. While some of these are estimated to hold significant shale gas potential, no major amendments have been made to the fiscal terms governing this round.

*Brazil Upstream Fiscal and Regulatory Report

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”

OPEC output dropped sharply in September, but non-OPEC supply growth is expected to approach record high in 2014

Global oil supplies declined by 625 000 barrels per day (650 kb/d) in September,  to 91.12 million barrels per day (mb/d), on steeply lower OPEC output, the IEA Oil Market Report for October told subscribers. But non‐OPEC supply growth for 2013 is forecast to average 1.1 mb/d, to 54.7 mb/d, rising to a near‐record 1.7 mb/d next year.

OPEC crude supplies slipped below 30 mb/d for the first time in almost two years, led by steep drops in Libya and Iraq. Output fell by 645 kb/d, to 29.99 mb/d, despite Saudi output exceeding 10 mb/d for a third month running. The "call on OPEC crude and stock change" was raised by 100 kb/d, to 29.6 mb/d, for the current quarter.

Recent demand strength has raised the 2013 forecast by 90 kb/d, to 91.0 mb/d. Demand growth for 2013 is projected at 1.0 mb/d (or 1.1%), ramping up to 1.1 mb/d in 2014 as the macroeconomic backdrop improves.

The Oil Market Report (OMR) is a monthly International Energy Agency publication which provides a view of the state of the international oil market and projections for oil supply and demand 12-18 months ahead. To subscribe, click here.

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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 Huisman,a worldwide specialist in lifting, drilling and subsea solutions, has secured a new contract from Helix Energy Solutions Group, Inc. for the delivery of a Well Intervention System onboard Helix’s new build Semi submersible “Q7000”. The system, which is based on Huisman’s proven Multi Purpose Tower (MPT) design, will be built by the Huisman production facility in China.

The fully integrated 800mt Well Intervention System will be capable of handling the Intervention stack, the high pressure riser and other components. The Huisman Multi Purpose Tower has the same functionality as a normal derrick but offers improved accessibility to the well center, which allows for new improved handling procedures that increase efficiency and safety. The superior accessibility to the well center and the small footprint of the MPT are ideally suited for well intervention and subsea installation services. Subsea equipment can be skidded into the well center from three sides, offering enhanced flexibility.

The active heave compensation hoist system of the MPT provides excellent means for safe landing of equipment at the seabed while the passive heave compensation system provides a safe and redundant means to supply top tension to the risers. A guide trolley, travelling the entire length of the tower, guides the subsea modules during lifting operations. The system also features multiple transfer hatches that can be used to move equipment into the well center, and a skiddable work floor covering the moonpool flush with main deck.

The skiddable work floor allows large subsea modules to be deployed, without the need for a raised work floor. When large objects need to pass the moonpool the work floor can be skidded aside. In closed position, the work floor is flush with the main deck, which significantly reduces HSE risks and improves equipment handling on deck.

In addition to the Well Intervention System Huisman will also supply a 150mt Knuckle Boom Crane and a 160mt Pedestal Mounted Crane. Previous orders from Helix, amongst others, the Multi Purpose Tower onboard the “Q4000”, “Well Enhancer” as well as the cranes for the “Q4000” and “Q5000”.

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. 

Noble Energy, Inc. (NYSE: NBL) announces that the A-2 appraisal well drilled on the Block 12 discovery offshore the Republic of Cyprus has successfully encountered approximately 120 feet of net natural gas pay within the targeted Miocene-aged sand intervals.  The Cyprus A-2 well, which is more than four miles northeast of the A-1 discovery location, was drilled to a total depth of 18,865 feet in 5,575 feet of water.

Production testing procedures were performed over a 39-foot section of the upper Miocene reservoir.  The test, limited by surface equipment, yielded a maximum flow rate of 56 million cubic feet per day (Mmcf/d) of natural gas.  Performance modeling indicates development wells in the reservoir should have capacity to deliver up to 250 Mmcf/d.  Evaluation of drilling data, wireline logs and reservoir performance information has resulted in an updated estimate of gross resources of the field ranging⁽¹⁾ from 3.6 trillion cubic feet (Tcf) of natural gas to 6 Tcf, with a mean of approximately 5 Tcf.  The Cyprus A structure represents the third largest field discovered to date within the Deepwater Levant Basin.

Keith Elliott, Noble Energy's Senior Vice President, Eastern Mediterranean, commented, "Results from the Cyprus A-2 well have confirmed substantial recoverable natural gas resources and high reservoir deliverability.  While the A-2 location has successfully defined the northern area of the discovery, we anticipate additional appraisal activities are necessary to further refine the ultimate recoverable resources and optimize field development planning.  In the meantime, we continue to identify and advance multiple development options.  In addition to the Cyprus A discovery, we are also encouraged about the further exploration potential in Block 12.  We have recently completed a 1,100 square mile 3D seismic acquisition, which will be interpreted over the next several months." 

Noble Energy operates Block 12 offshore the Republic of Cyprus with a 70 percent working interest.  Delek Drilling and Avner Oil Exploration each have 15 percent working interest. 

Noble Energy plans to move the Ensco 5006 drilling rig to Tamar SW, offshore Israel, at the completion of operations offshore Cyprus.  The Tamar SW well, testing an exploration prospect offsetting the main Tamar field, is expected to reach total depth by the end of 2013.  Noble Energy operates Tamar SW with a 36 percent working interest.   

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

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.