Mitsubishi Corporation (MC) announced August 24 that it has entered into an agreement  worth US$3.5 billion over 15 years in connection with investing in a natural gas development project centered on shale gas in the Cordova Embayment of northeastern British Columbia, Canada. The project is owned by a senior independent Canadian oil and natural gas producer, Penn West Energy Trust (PWE).

MC will acquire a 50 percent interest in shale gas assets, conventional natural gas assets and related natural gas facilities in several sections owned by PWE. An unincorporated joint venture (JV) to be formed with PWE will actively develop and produce natural gas.

PWE has been conducting initial drilling operations since 2006 and, based upon third party evaluations, Mitsubishi believes that the shale gas resources in this project are approximately 5-8 tcf (over 100~160 million tons in LNG equivalents). The potential of this enormous resource could greatly exceed Japan’s natural gas annual demand, the company said.

The initial plans of the JV are to lift current output of approximately 30 MMcf/d to approximately 500 MMcf/d (approximately 3.5 million tons of LNG equivalents per year) based upon current and anticipated economic, regulatory and market conditions. MC's equity share of production will be 50 percent. MC will promote development and production in this region for over the next 50 years together with PWE and market natural gas of MC’s equity share of production in the North American market. Going forward, this project will drill more than hundreds to 1,000 wells for coming 15 years.

Trinidad and Venezuela signed an agreement August 16 for the joint development of the Loran-Manatee field, which spans both countries’ maritime borders, Upstream reported, citing Trinidad Energy Minister Caroline Seepersad-Bachan. The Loran-Manatee field is estimated to contain 10 tcf of gas, 7.3 tcf of the reservoir on the Venezuelan side and 2.7 tcf on the Trinidad side. The "unitization of reserves" agreement was a significant achievement for both nations, Seepersad-Bachan told Reuters. "It is the first of its kind in the region and speaks volumes for how much we as nations and as an entire region have matured in our cross-border relations," she said. The agreement comes at a time when Trinidad is looking to fresh gas reserves to replace production, as proved gas reserves dropped to 14.4 tcf in 2008 from 17 tcf in 2007. Chevron is operator of the Loran field in Venezuela, while Chevron (operator) and BG Group are partners in the Manatee field on the Trinidad side.

Chevron announced August 12 a natural gas discovery in the Exmouth Plateau area of the Carnarvon Basin offshore Western Australia. The Brederode-1 exploration well is located within the WA-364-P permit area approximately 217 miles northwest of Onslow.  Situated in 4,550 feet of water, the well was drilled to a depth of 9,022 feet and encountered approximately 49 feet of net gas pay.

George Kirkland, vice chairman, Chevron, said, "We are encouraged by the Brederode-1 exploration success, which is further evidence of the natural gas potential in the Exmouth Plateau area and the frontier opportunities offshore northwest Australia.” 

Jim Blackwell, president, Chevron Asia Pacific Exploration and Production Co., said the  Brederode-1 discovery, which follows  the 2009 Kentish Knock discovery in the same area, extends the gas resources farther offshore Australia and continues to grow the company's discovered gas portfolio in Australia.

“This discovery expands the resource potential in the Carnarvon Basin frontier and demonstrates our long-term commitment to developing Australia’s world-class natural gas resources,” said Blackwell. Chevron is the largest holder of undeveloped gas resources in Australia.  Chevron’s is the operator of WA-364-P with 50 percent interest.  Shell also holds 50 percent interest.

Artumas Group (Artumas) announced July 7 that the company has signed a Memorandum of Understanding (MOU) with the Government of Tanzania and the Tanzanian Petroleum Development Corporation to proceed with a pre-feasibility study into the monetization of the natural gas assets in Mnazi Bay with a focus on ammonia/urea/methanol. The pre-feasibility study will assess the economic viability of a world-scale ammonia/urea/methanol project, as well as examining alternative monetization projects using the substantial gas resources in Mnazi Bay, Tanzania.  The project, if proven viable, would be East Africa’s first world-scale petrochemical project. The MOU provides for a 12 month development period to define and assess the economic viability of a project.  It further allows the project to be considered for development within the framework of the existing Production Sharing Agreement.

Map depicting the location of Artumas’ Manazil Bay resources. Courtesy Artumas Group.

Petronas may begin exporting gas from Ethiopia in 2015 after a production build-up from its Calub and Hilala gas fields, Bloomberg reported July 2, citing a Mines Ministry official. "After five years, Ethiopia will become a producer of natural gas. Our focus will be on the export sector since the local market will consume little," said Eshetu Chala, a senior economist at the ministry. Annual production rates have yet to be determined. "Drilling is going on, but the output capacity will be determined after an appraisal of reserves," said Chala. In 2007, Petronas paid US$80 million for the rights to develop the fields. The fields are located in the Ogaden basin and may contain as much as 4 tcf of recoverable gas. Petronas also plans to build a gas-treatment plant and gas pipeline to a port in Djibouti for US$1.9 billion, according to the Reporter, an Ethiopian newspaper.

Dominion Petroleum (Dominion) announced June 28 the results of a competent persons report (CPR) on the first prospect in Block 7, offshore deep-water Tanzania. The "Alpha" prospect has a mean prospective resource of 1.104 billion barrels of oil or 7.069 tcf of gas, based on the CPR recently concluded by Energy Resource Consultants Ltd. (ERC). ERC have risked the prospect with a 12 percent Chance of Success (CoS) as a whole (differing CoS for different objectives ranging from 9 percent-15 percent within Alpha); net risked mean resource: 134 MMbo or 848 bcf. Alpha is in water depths of up to 4,000 feet and represents multiple drilling objectives all the way down to 16,000 feet.

The Alpha prospect was identified by the existing 4,350 kilometers of 2D seismic coverage and is supported by amplitude variations with offset studies performed this year. This is the first prospect in the block and the CPR work undertaken on Alpha was intended to assist in planning a 1,000-sq km 3D seismic survey. This survey should begin next month and should take approximately 60 days to acquire, the company said. Once completed, Dominion will initiate further work on the other prospects and leads already identified in the 2D seismic.

New Standard Energy (NSE) announced June 22 a number of significant advances and developments pertaining to the company's exploration efforts in the Canning Basin, Western Australia. The recent developments include a new independent report confirming the large shale gas resource potential of the Goldwyer sub-basin in the Canning Basin. An independent and publicly available upstream industry report produced by RISC has confirmed the resource and commercialization potential of the Goldwyer shale exploration play in the Canning Basin, NSE said.

            RISC is an internationally recognized consultancy with expertise in the oil and gas sector. The report entitled “Unconventional Gas in Australia, May 2010” is a comprehensive review of coal seam, shale and tight gas in Australia. The review highlighted: The huge potential for the Canning Basin; Potential gas initially in place of 40 - 480 tcf over the most prospective parts of the Goldwyer Formation (estimated to be around 80,000 sq km); and potential for Canning Basin gas to be supplied economically to market at prices currently being enjoyed in the Western Australian gas market.

Kea Petroleum (Kea) announced June 16 that the Beluga-1 well, in exploration permit PEP51155 in the Taranaki basin of New Zealand, has reached a total depth of 4,100 m, having intersected a number of sands with indications of hydrocarbon presence, including a zone which encountered higher pressure. Gas was detected on the surface and waxy condensate coated the upper parts of the drill pipe. Wireline logs will enable Kea and its partner Methanex to evaluate the significance of these shows and to make a decision whether to case the well in preparation for flow testing. In January 2010, Kea and Methanex entered into an agreement whereby Methanex will contribute up to US$10 million to drill, complete and test one exploration well (Beluga-1) on Kea’s permit PEP 51155.

In the event of a discovery of gas of commercial quantities Methanex has agreed to purchase and Kea has agreed to sell the gas under a 15-year gas offtake agreement. Methanex presently consumes 30 bcf of gas per annum and has a potential demand for up to 90 bcf if all existing production capacity was returned to active processing. The price Methanex will pay for this gas fluctuates with the international price of methanol subject to both a floor and a ceiling price.

The Beluga drill site. Courtesy Kea Petroleum.