World of oil and gas

EXPLORATION

Noble Energy will resume Falklands drilling in 2015

Following the acquisition, and evaluation, of an extensive 3D seismic program over portions of the company’s 10-million-acre position, Noble Energy (35% WI, operator) plans to resume exploration drilling offshore the Falkland Islands in 2015. Noble’s initial operated prospect has been named Humpback and is in the Fitzroy sub-basin of the Southern Area license. The Humpback prospect is one of multiple, stacked fan prospects, clustered together in the sub-basin. This group of prospects, combined, has an estimated, gross, unrisked resource potential of approximately 1 Bboe. The company anticipates beginning its drilling at Humpback in mid-2015. Noble is finalizing pros-pect locations for a second exploration well, planned for later in 2015, following results at Humpback. The Scotia well, drilled in 2012 with 2D seismic interpretation, has been deemed non-commercial.  Mike Putnam, Noble Energy’s V.P. of Exploration, said, “We are excited about our upcoming exploration program in the Falkland Islands where we will be testing a basin with multibillion barrel potential. Our recent 3D seismic acquisition has confirmed our initial thoughts that the basin contains prospects of material size with ample follow on opportunities.”

Woodside farms into PSC offshore Cameroon

Woodside Petroleum has finalized an agreement with Noble Energy and Glencore to farm into the Tilapia production sharing contract (PSC) off the southwestern coast of Cameroon. The 3,875-km² block is within the Douala basin, in water depths ranging from the shoreline to 1,100 m. Under the agreement, Woodside will acquire a 30% non-operating interest. Noble Energy will retain 46.67% and continue to operate the PSC; Glencore holds 23.33%. The JV plans to drill the Cheetah exploration well in 2015. Woodside CEO Peter Coleman said the Douala basin represents an exciting opportunity, with demonstrated oil prospectivity. This farm-in agreement follows Woodside’s acquisitions, since July, of new acreage in Gabon, Tanzania and Morocco.

Eni signs PSCs to explore offshore Vietnam

Eni and Petrovietnam have signed two PSCs for the exploration of Blocks 116 and 124, off the coast of Vietnam. Block 116 covers an area of about 5,000 km² in the Song Hong basin, in water depths ranging from 10 to 120 m. The block, wholly owned by Eni, provides for an exploration period of seven years, divided into three phases. Block 124 covers 6,000 km² in the Phu Khanh basin, in water depths ranging from 50 to 2,600 m. This PSC has an exploration period of seven years, divided into two phases. Eni is operator (60%), and Santos Vietnam holds a 40% stake. “The participation in these two new high-potential blocks will consolidate our presence in the area and support our growth in the Pacific basin,” said Claudio Descalzi, Eni’s CEO.

TGS is expanding its Constitution group of WAZ 3D projects with the commencement of the Declaration survey. Declaration will cover 6,061 km² (260 OCS blocks) in the Mississippi Canyon and Viosca Knoll protraction areas of the central Gulf of Mexico. It will be acquired orthogonal to TGS’ underlying Justice WAZ 3D survey. With offsets to 16 km, these data will be acquired by CGG with a single-pass vessel configuration derived from its StagSeis technology, to better image deep structural elements, and to improve subsalt and salt flank illumination. Data will be processed as a stand-alone volume and also be integrated with TGS’ existing Justice data, to provide orthogonal wide-azimuth (M-WAZ) coverage over the area. The data will be processed using TGS imaging technology, including Clari-Fi and Orthorhombic migrations.  Preliminary data will be available to the industry at the beginning of 2015, ahead of OCS Lease Sale 235. Acquisition commenced in October, utilizing five vessels from the CGG fleet.

GOVERNMENT/REGULATORY  

Baker Hughes has implemented a new policy of disclosing 100% of the chemistry contained within its hydraulic fracturing fluid systems, without the use of any trade secret designations. The company announced, in March of this year, its plans to provide complete lists of all of its products and chemical constituents. This will hold true for all wells that it fractures, using its fracing fluid products, without detailing specific product formulations. For each fracturing job the company performs, on or after Oct. 1, the policy mandates that Baker Hughes will disclose a single list of all of the chemical constituents of its products used, while also specifying their maximum concentrations.

To address widespread concerns about fracing risks, particularly related to the contamination of groundwater, DNV GL has invited upstream firms and other stakeholders to a joint industry project (JIP). The aim is to collect data, develop and validate quantitative risk assessment methodologies, and outline risk management strategies that can be accepted widely by all relevant parties. The shale industry encompasses a great number of companies, thus aggregated, quantifiable fracing-related data are hard to come by. This makes it more difficult for various stakeholders to assess fracing risks, given various well depths, geological formations, and mixes of fracing solution components. DNV GL proposes to bring together key stakeholders from all over the world: operators, service companies, academics, financiers, regulators and other interested parties. The JIP will collect and analyze shale gas fracing-related data, apply statistical methodologies, and then define quantitative measures of fracing risk to both horizontal and vertical portions of a well.

Mexico will begin the prequalification process for shallow-water bids in the first-half of November, according to officials with Mexico’s Energy Department. After the shallow-water round is complete, Undersecretary of Hydrocarbons Maria de Lourdes Melgar Palacios said the bidding sequence will go as follows: extra-heavy oil, unconventional assets and deep water. Round One will include the sale of 169 blocks—109 to be exploratory—and will be in areas that already have much infrastructure in place. About 28,500 km² will be offered. Mexican officials said there is potential for more than 18 Bboe in cumulative prospective resources, and proven and probable reserves. Prequalification will go on until January 2015, said Juan Carlos Zepeda Molina, president of the National Hydrocarbons Commission.

Statoil and co-venturer Exxon Mobil’s Giligiliani-1 exploration well has resulted in a new natural gas discovery offshore Tanzania. The discovery of an additional 1.2 Tcf of gas-in-place in Giligiliani-1 brings the total of in-place volumes up to approximately 21 Tcf in Block 2. The discovery is along the western side of Block 2, at a water depth of 2,500 m. The discovery was found in Upper Cretaceous sandstones. The Discoverer Americas rig will now drill the Kungamanga prospect in the central part of Block 2. 

Lundin Petroleum, through its wholly owned subsidiary, Lundin Norway, has finished drilling exploration well 7220/11-1 on the Alta prospect in the Barents Sea. The main objective was to prove the presence of hydrocarbons in reservoir rocks of Permo-Carboniferous and Triassic age. The well encountered a 57-m, gross hydrocarbon column, consisting of 11 m of gas and 46 m of oil, in carbonate rocks of good reservoir quality. The preliminary evaluation of  gross recoverable oil and gas resources in the Alta accumulation is estimated at 125 MMboe to 400 MMboe. The oil resource range is estimated at 85 MMbbl to 310 MMbbl.

Petrobras has confirmed an extension of the hydrocarbon accumulation in the Espirito Santo basin’s post-salt ultra-deep waters, through the drilling of appraisal well 3-ESS-219D, informally known as Pudim. The well is in the Brigadeiro Discovery Evaluation Plan (PAD) area, 121 km from the city of Vitoria, Espirito Santo state. Log data analysis, fluid samples and cable tests from reservoirs, some 3,550 m deep, have confirmed the presence of good-quality oil. Petrobras operates the PAD consortium, in partnership with Shell (20%) and Inpex Petroleo Santos (15%).

Statoil’s 7220/2-1 wildcat found between 1 Bcm and 2 Bcm of recoverable gas, said the Norwegian Petroleum Directorate. The well was drilled about 40 km northeast of the Johan Castberg oil and gas discovery, 7220/8-1, in the Barents Sea. The well encountered an 85-m gas column in the Stø and Nordmela formations, with a reservoir quality ranging from very good to excellent. The Snadd formation was found to have more varied reservoir properties, but it is an aquifer. The well was drilled in a water depth of 429 m, to a TVD of 1,554 m below the sea surface, and was terminated in the Snadd formation. Drilled by the Transocean Spitsbergen, the well was permanently plugged and abandoned.

BUSINESS

PRODUCTION

Chevron Canada Limited, is selling a 30% interest in its Duvernay shale play to Kuwait Foreign Petroleum Exploration Company’s wholly-owned subsidiary, KUFPEC Canada Inc., for $1.5 billion. The total purchase price includes cash paid at closing, as well as a carry of a portion of Chevron Canada’s share of the JV’s future capital costs. The Duvernay is in west-central Alberta. The agreement creates a partnership for appraisal and development of liquids-rich shale resources in approximately 330,000 net acres in the Kaybob area of the Duvernay. Following closing, Chevron Canada will hold a 70% interest in the JV Duvernay acreage and remain the operator. Chevron Canada has drilled 16 wells since beginning its exploration program, with initial well production rates of up to 7.5 MMcfgd and 1,300 bcpd. A pad drilling program recently began, which is intended to further evaluate and optimize reservoir performance, as well as reduce execution costs and cycle time.

Statoil has sold its 15.5% participating interest in the Shah Deniz PSA, a 15.5% share in the South Caucasus Pipeline Company (SCPC), a 15.5% share in the SCPC holding company, and a 12.4% share in the Azerbaijan Gas Supply Company to Petronas for $2.25 billion. Statoil’s 2014 second-quarter production from Shah Deniz field was 38,000 boed. Shah Deniz field was discovered in 1999, on the deepwater shelf of the Caspian Sea, 70 km southeast of Baku, in water depths ranging from 50 to 500 m. Shah Deniz Stage 1 began operations in 2006. The Shah Deniz partners are producing approximately 26 MMcmgd and 53,000 bcpd. Shah Deniz is operated by BP (28.8%). Partners include TPAO (19%), SOCAR (16.7%), Lukoil (10%) and Nico (10%).