OGJ Newsletter

July 7, 2014
International news for oil and gas professionals

IntGENERAL INTERESTQuick Takes

Freeport-MMR completes purchase of gulf assets

Freeport-McMoRan Oil & Gas LLC, a subsidiary of Freeport-McMoRan Copper & Gold Inc., has completed its $1.4 billion acquisition of certain interests in the deepwater Gulf of Mexico from Apache Corp. (OGJ Online, May 8, 2014).

The deal encompasses interests in the Lucius and Heidelberg oil production development projects and 11 exploration leases.

Following the exercise of preferential purchase rights by other working interest owners in the Lucius project, Freeport-McMoRan O&G acquired 51.2% of Apache's 11.7% working interest in the Lucius oil development project, 100% of Apache's 12.5% working interest in the Heidelberg oil development project, and several exploration leases for $919 million.

Following closing and the interim redetermination of equity ownership by the co-owners in Lucius field, Freeport-McMoRan O&G owns 25.1% working interest in Lucius.

The acquisition was funded with proceeds from Freeport-McMoRan O&G's sale of Eagle Ford assets to Encana Oil & Gas Inc., which closed on June 20 (OGJ Online, May 7, 2014). The estimated combined aftertax net proceeds from these transactions total $1.8 billion.

Puma to buy InterOil's downstream PNG businesses

Singapore-based Puma Energy Group Pte. has acquired the InterOil Corp. subsidiaries holding the company's Papua New Guinea refining and petroleum products distribution businesses for $525.6 million.

The downstream businesses include the 28,000-b/d Napa Napa refinery in Port Moresby, 52 retail outlets, and 30 fuel depots, terminals, and aviation sites (OGJ, Mar. 19, 2001, p. 46).

The transaction ensures the transition of InterOil's staff at the refinery and downstream businesses to Puma. Puma and InterOil will begin the handover of operations and transition of staff immediately.

As a condition of the deal, Puma may use the InterOil downstream brand for as long as 12 months.

Puma distributes petroleum products in more than 40 countries and operates 1,700 retail outlets, more than 60 terminals, and a refinery. It has regional hubs in Australia, South Africa, South America, and Europe.

"This investment marks an important step in the execution of our regional strategy and offers considerable synergy with our developments in Australia and the broader Pacific region," said Pierre Eladari, Puma chief executive officer.

Jon Ozturgut, InterOil chief operating officer, said the sale arose from an unsolicited approach by Puma and a subsequent strategic review by InterOil of options on how to best allocate capital.

"The transaction immediately provides additional capital to fund our upstream and LNG business," he said (OGJ Online, Nov. 12, 2013; Nov. 26, 2012).

InterOil's upstream assets include Asia's undeveloped Elk-Antelope gas field in the Gulf Province and exploration licenses covering about 16,000 sq km. InterOil in December 2013 made a billion-dollar joint venture deal with Total SA for development of its gas reserves in Elk-Antelope (OGJ Online, Dec. 6, 2013; Mar. 26, 2014).

MOL to acquire licenses in UK North Sea

MOL Group has agreed to acquire interest in six licenses in the UK North Sea from Premier Oil UK Ltd. for $130 million.

The deal includes nonoperated equity stakes in the Nexen Inc.-operated Scott (21.84%), Rochelle (15%), and Telford (1.59%) fields, as well as participating interest in further exploration licenses such as the Rochelle Upper Jurassic deep prospect.

Nexen started production from Rochelle in October 2013. The field lies in 140 m of water on Blocks 15/26b, 15/26c, and 15/27 about 115 miles northeast of Aberdeen (OGJ Online, Oct. 25, 2013).

MOL estimates the deal increases its 2P reserves by 14.3 million boe from the three producing fields, of which Scott represents 9.3 million boe, Rochelle 4.4 million boe, and Telford 0.5 million boe. The three fields are comprised of 73% oil and 27% gas.

The company also sees further prospective resources totaling 7 million boe unrisked. Year-to-date production from the assets averages 3,700 boe/d, with peak production expected to reach 6,200 boe/d in 2016.

MOL says the deal creates "considerable operational synergies" with the company's existing assets in the UK North Sea. Overall UK peak production for the company is now expected to reach 20,000-22,000 boe/d in 2018.

MOL in March completed a transaction in which it acquired offshore assets with 14 licenses in the North Sea from Wintershall for $375 million. During that time, the company set up an office in Aberdeen to support its operations and future expansion in the region (OGJ Online, Mar. 25, 2014).

Premier sells interest in Indonesian block

Premier Oil PLC, London, has sold the wholly owned subsidiary that holds a 41.67% equity interest in Block A, Aceh Province, in North Sumatra, Indonesia, to KrisEnergy Asia Holdings BV for after-tax consideration of $40 million plus working capital adjustments.

PT Medco Energi, Jakarta, operates the block, on which it reported an indicated natural gas discovery in the Matang-1 exploratory well last year (OGJ Online, Apr. 23, 2013). Also on the block are undeveloped Alur Siwah, Alur Rambong, Julu Rayeu, and Kuala Langsa gas fields.

Medco Energi holds a 41.67% interest, and Japan Petroleum Exploration Co. Ltd. holds 16.66%.

Exploration & DevelopmentQuick Takes

Petrobras starts extended well test at Iara

Petroleo Brasileiro SA (Petrobras) has started an extended well test (EWT) in the Iara evaluation area on Block BM-S-11, 300 km offshore Brazil in 2,200 m of water.

The EWT—part of the Discovery Evaluation Program approved by Brazil's National Petroleum, Natural Gas, and Biofuels Agency (ANP)—is being conducted on the 3-BRSA-1132-RJS (RJS-706) well in the western portion of the Iara Evaluation Plan, using the Dynamic Producer floating production, storage, and offloading vessel.

Petrobras says the well's initial production of 29,000 b/d of oil is similar to production of wells that are currently producing for commercial purposes in the Santos basin presalt, indicating the area's "enormous potential."

The EWT is the first to be carried out in Iara, and will facilitate the acquisition of data for development of the 2008 discovery (OGJ Online, Aug. 8, 2008; Sept. 12, 2008). At the time, Petrobras said it expected the field to yield 3-4 billion boe of recoverable light crude and natural gas.

Petrobras last summer found that the presalt carbonate reservoirs in the fourth exploratory well in the Iara area have better characteristics than those found in the Iara discovery well (OGJ Online, July 25, 2013).

Later that year, the company identified a 310-m hydrocarbon column in a fifth exploratory well, with reservoir characteristics similar to those found in the vertical discovery well that encountered good quality 28° gravity oil (OGJ Online, Nov. 13, 2013).

The Evaluation Plan will expire at yearend, at which point the consortium is required to submit the declaration of commerciality to the ANP.

Petrobras is operator of Iara with 65% interest. Partners are BG E&P Brasil Ltda. 25% and Petrogal Brasil SA 10%.

GeoPark reports oil discovery on Campanario block in Chile

GeoPark Holdings Ltd. has reported an oil discovery on its newly acquired Campanario block in Tierra del Fuego, Chile.

The company drilled and completed the Primavera Sur 1 well to a total depth of 8,025 ft. A test conducted in the Tobifera formation at 7,750 ft resulted in a production rate of 215 b/d of 39.9° gravity oil.

GeoPark says production testing will be required to determine stabilized flow rates as well as the extent of the reservoir. Surface facilities and systems already exists to produce and distribute the oil from this well. Seismic interpretation of the Primavera Sur prospect indicates the opportunity for future development drilling following more testing.

GeoPark said it has identified 30 prospects to be drilled on its Isla Norte, Campanario, and Flamenco blocks (OGJ Online, July 2, 2013). The company is in the midst of a $150 million work program in Chile this year.

GeoPark operates Campanario block with 50% working interest, partnering with Chilean state-owned Empresa Nacional de Petroleo de Chile (ENAP).

NEB okays Baffin Bay, Davis Strait survey

Canada's National Energy Board has approved a 2D seismic survey in the Baffin Bay and Davis Strait.

A joint venture of TGS NOPEC Geophysical Co. and MultiKlient Invest AS (MKI), a wholly owned subsidiary of Petroleum GeoServices, will conduct the survey during July-November open-water seasons over 5 years. MKI is project operator.

The venture will acquire as much as 16,173 line-km of seismic data in an area seaward of Canada's 12 nautical-mile boundary and outside the Outer Land Fast Ice Zone to the Greenland border. The northern extent of the project area is about 180 km from the mouth of the Landcaster Sound. The southern extent is 61° N. Lat.

The NEB imposed 15 conditions on the approval, including reporting requirements related to environmental commitments.

Drilling & ProductionQuick Takes

More time needed for Johan Castberg project

Partners in the Johan Castberg license—Statoil ASA, Eni SPA, and Petoro—have decided to "spend more time on making the final concept selection" for the Johan Castberg project.

Statoil and its PL532 partners earlier this year concluded the 2013-14 Johan Castberg field exploration program by making an oil and gas discovery in the Drivis prospect in the Barents Sea (OGJ Online, May 2, 2014). The find represented the second oil discovery in the field, but fell beneath Statoil's volume expections.

"The companies will continue efforts to mature the technical development solution, updating the resource basis and reducing cost leading up to the summer of 2015," said Arne Sigve Nylund, Statoil executive vice-president for development and production, Norway. "The partners will also further assess the financial basis for an oil terminal at Veidnes," Nylund said.

The Johan Castberg project comprises the Statoil-operated Skrugard discovery, made in 2011, and the Havis discovery, made in 2012. The discoveries were a breakthrough for the Barents Sea as a new oil province, Statoil said. Proved volumes in Johan Castberg are estimated at 400-600 million bbl of oil.

As operator of the Johan Castberg license, Statoil said, it has carried out an "extensive exploration campaign" in order to prove additional resources that could make the field "sufficiently viable." The 12-month exploration campaign comprised a total of five wells at multiple reservoir depths.

"Unfortunately, the exploration campaign has proven less new oil resources in the Castberg area than expected. In total, we have not proven enough resources in Castberg to make the field viable for supporting infrastructure, including a pipeline to shore and an onshore terminal on its own," Nylund said.

Government support practices for this type of infrastructure also remain unclear.

Statoil lets jacket contract for Johan Sverdrup oil field

Statoil ASA has entered into a framework agreement with Kvaerner ASA for the delivery of jackets in the North Sea until 2020. The companies also will sign a letter of intent for the delivery of two jackets to Johan Sverdrup oil field, which lies in 110 m of water across production licenses 265, 501, and 502 in the Utsira High area in the Norwegian North Sea, 140 km west of Stavanger.

The framework agreement allows Kvaerner to perform engineering, purchasing, and steel jacket construction in the North Sea until 2020. Statoil says the agreement ensures greater consistency and secures the company access to expertise and capacity crucial to forthcoming developments.

Johan Sverdrup is the first development covered by the framework agreement, which includes four installations and jackets.

The two jackets subject to the letter of intent are for Johan Sverdrup's riser platform and drilling platform, which Statoil describes as the two largest and most demanding steel jackets at the field center. The jacket for the riser platform is due for delivery in summer 2017 and the drilling platform jacket in spring 2018.

The letter of intent for the first two platforms on Johan Sverdrup is contingent on an investment decision for the field being reached in February 2015.

Kvaerner has been involved in the development of Johan Sverdrup as Aker Solutions' subcontractor for jacket design on the field center pre-project.

The contracts for the steel jacket for the accommodation quarters and the processing plant are expected to be let in the middle of 2015. Kvaerner is one of several potential suppliers, Statoil says.

A concept for the first development phase of Johan Sverdrup was selected in February. Production is expected to start in late 2019, with a field production horizon reaching beyond 2050 (OGJ Online, Feb. 13, 2014).

More Mumbai High (North) development due

Oil & Natural Gas Corp. will install five wellhead platforms and drill 52 wells and 24 sidetrack wells in a third phase of redevelopoment of Mumbai High (North) oil field offshore western India.

The state-owned company has approved capital investment of $743 million in the project.

ONGC plans to install five well platforms and modify 13 platforms. The project also includes one clamp-on facility for wells at an existing platform and associated pipelines.

Facilities are to be installed by April 2016. The project is to be complete by May 2017.

ONGC expects the new phase to boost field recovery by 51 million bbl of crude oil and 186 bcf of natural gas by 2030.

PROCESSINGQuick Takes

ExxonMobil lets contract for Gulf Coast ethylene project

ExxonMobil Corp. has let a contract to a joint venture of Germany's Linde Group and Bechtel, Houston, to design and build an ethylene plant included in the expansion at the major's Baytown, Tex., refining and petrochemical complex (OGJ Online, June 19, 2014; July 1, 2013; June 5, 2012).

Construction on the plant—which is to have an ethylene production capacity of 1.55 million tonnes/year—will begin immediately, with design and procurement of key equipment already under way, Bechtel and Linde confirmed in a joint release.

Linde will provide engineering, procurement, and services during precommissioning and commissioning of the plant, while Bechtel will be responsible for the plant's construction as well as related procurement, the companies said.

In its recent announcement that construction had begun on the multibillion-dollar expansion at Baytown, ExxonMobil said it had awarded contracts to Linde Engineering North America Inc. and Bechtel Oil, Gas & Chemicals Inc. to build olefins recovery units for the project, with additional contracts awarded to Mitsui Engineering & Shipbuilding Co. Ltd. and Huertey Petrochem SA to construct the olefins furnaces (OGJ Online, June 19, 2014).

Petronas lets contract for RAPID project

Malaysia's state-run Petronas has let a program management consultancy (PMC) contract to a Technip SA-led joint venture with Fluor Corp. for its proposed $20 billion refinery and petrochemical integrated development (RAPID) complex at Pengerang in southeastern Johor, Malaysia (OGJ Online, May 13, 2011).

The PMC contract will include overall project and site management of the RAPID project and provision of project management services for specific engineering, procurement, construction, and commissioning (EPCC) packages within RAPID throughout the project stages, as well as warranty management and close-out phases, Technip said.

This PMC contract, which will be executed by Technip's operating center in Kuala Lumpur, follows the March 2012 award of front-end engineering and design to Technip for the RAPID project (OGJ Online, Mar. 13, 2012).

Technip PMC, the company's new division focused solely on PMC services, also will participate in project execution, Technip said.

Petronas is poised for its refinery start-up by early 2019, according to Technip.

With a planned capacity of 300,000 b/d, the proposed RAPID refinery will produce naphtha and liquid petroleum gas feedstock for the petrochemical complex, as well as gasoline and diesel meeting European specifications to help address Asia-Pacific's growing need for petroleum and petrochemical products (OGJ Online, Mar. 27, 2014; Mar. 13, 2012).

In addition to production units that include a naphtha steam cracker, the RAPID development will provide storage and logistics facilities for a number of dry and liquid bulk products (OGJ Online, Mar. 27, 2014).

PDVSA lets contract for Puerto Laz Cruz refinery project

Petroleos de Venezuela SA (PDVSA) has let a contract to a consortium led by Hyundai Engineering & Construction Co. Ltd. for the expansion and modernization of its 190,000-b/d Puerto La Cruz refinery in eastern Venezuela.

The $4.8 billion contract, in which Hyundai E&C holds 72% interest, also includes Hyundai Engineering Co. Ltd. (18%) and Wison Engineering Ltd. (10%), Hyundai E&C said.

The project, which will entail the remodeling of existing installations and equipment at the refinery as well as some construction to improve the yield of higher-quality products, will last 47 months from initial groundbreaking, according to Hyundai E&C.

No firm dates were disclosed for either the project's groundbreaking or completion.

PDVSA previously has signed a series of agreements for an overhaul of the Puerto La Cruz refinery to equip the plant to process a heavier slate of crude oil feedstocks (OGJ Online, July 1, 2013; May 13, 2013; Oct. 17, 2008; Mar. 15, 2007).

TRANSPORTATIONQuick Takes

Fatal gas line blast in India investigated

GAIL (India) Ltd. and the Indian government are investigating a natural gas pipeline explosion that killed 19 persons and injured 19 in the village of Nagaram near a gas collection station in Tatipaka in Andhra Pradesh, India. The cause hasn't been determined.

The June 27 blast occurred on GAIL's Tatipaka-Kondapalli pipeline.

GAIL and the Indian government committed to make compensation payments to families of the victims and to the injured and to provide other forms of relief in the area of the blast.

Woodside, Cheniere unit sign LNG supply deal

Woodside Energy Trading Singapore has signed a binding LNG supply agreement with Cheniere Energy's subsidiary Corpus Christi Liquefaction LLC for the purchase of 850,000 tonnes/year of LNG from the Corpus Christi LNG project when the second train at the export facility comes on stream. The facility will eventually have three trains with a combined capacity of 13.5 million tpy.

LNG will be bought on a FOB basis. Woodside will pay 115% of the monthly Henry Hub price plus $3.50/MMbtu.

The Woodside agreement is for 20 years, but includes an extension of up to an additional 10 years along with a mechanism that gives Woodside an option to forgo deliveries with sufficient notice through the payment of $3.50/MMbtu for cancelled amounts.

Cargos are scheduled to begin from Train 2 in 2019.

The deal will give Woodside's trading arm access to the US shale industry that is predicted to enter the global market by 2020.

Woodside's trading arm already sells uncommitted LNG from the company's Pluto facility on the Burrup Peninsula in Western Australia.

Woodside Chief Executive Officer Peter Coleman said the Corpus Christi agreement diversifies Woodside's LNG offering and demonstrates how the company is extending and enhancing its marketing and trading capabilities as well as adding value to the portfolio.

Coleman added that Woodside sees US LNG to be attractive to LNG purchasers and complement the company's existing LNG portfolio as well as enable it to exploit new opportunities.

BG begins coal-seam gas commissioning for QCLNG project

BG Group has started commissioning its Surat basin coal-seam gas processing network that will send supplies of gas to the company's Queensland Curtis LNG (QCLNG) project.

A total of 17 field compressor stations and four central processing plants at three Surat basin hubs at Chinchilla, Wandoan, and Dalby make up the gas gathering and supply system.

One of the key central facilities, named the Ruby Jo processing plant, has a nameplate processing capacity of 440 MMcfd of gas. The other three plants are similar, and the system will transport gas through a 540-km buried pipeline to the QCLNG plant near Gladstone.

The central processing plants and field compression stations have been constructed during the last 2½ years by 1,500 engineers, civil works contractors, mechanics, welders, electricians, and others.

Gas will enter the system at the significant pressure of 10,000 kPa.

The $20.4 billion project is due to come on stream and start exports of LNG in December. When fully on stream the project will produce 8.5 million tonnes/year of LNG.

BG says the project is still open to securing more third-party gas to feed into the pipelines.