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.

Magellan Petroleum Corporation (Magellan) announced that Australia’s Foreign Investment Review Board has indicated they have “no objection” to Magellan’s acquisition of Santos' 40 percent interest in the Evans Shoal natural gas field (NT/P48). The Evans Shoal field is very large with estimated contingent natural gas resource of between 6.5 and 8 tcf, including CO2 content and gas condensate resource totalling more than 30 million barrels.

                Evans Shoal was discovered in 1988.  It lies in a range of water depths from very shallow to more than 300 feet and has had three wells drilled. Subsequent drill stem testing flowed gas at a stabilized rate of 25 MMcf/d.The field contains a substantial quantity of CO2. CO2 is a significant feed component for the production of Methanol but can add cost to LNG development. The Evans Shoal acquisition could give Magellan and its partners a development opportunity with regard to Asia’s growing LNG and Methanol markets, the company said.

The Indonesian government has decided that 70 percent of gas production from the Donggi-Senoro fields in Central Sulawesi will be exported. According to the Ministry of Energy and Mienral Resources, the gas export percentage was a final option based upon the calculation that the fields did not contain sufficient gas to cover domestic gas supply until 2014. The gas will be exported from the planned PT Donggi Senoro LNG plant. The domestic gas needs will largely be supplied by other sources, such as ExxonMobil's Cepu block.

Three Japanese buyers are still lined up to buy LNG from the PT Donggo Senoro LNG venture, after Japan's Kansai Electric Power terminated its agreement to buy LNG from the plant in August 2009 due to the government's delay on gas allocation. The remaining buyers include Chubu Power, Kyushu Electric Power Company and Korea Gas Corporation.  PT Medco holds a 20 percent stake in the LNG export venture, while Mitsubishi Corporation holds a controlling 51 percent and Pertamina holds a 29 percent stake.

Petrobras announced it acquired 100% of the rights for Block 2, located in the Raukumara Basin, offshore New Zealand. The block was offered in a public tender organized by the New Zealand Government (Block Offer 2010), held in January 2010, in which Petrobras was the highest bidder. On June 1, Petrobras and the Government of New Zealand formalized the agreement, and the company was granted the Petroleum Exploration Permit for Block 2.

Petrobras takes-on obligations to execute a minimum work program, divided into three stages: Stage 1 - 3,000 km of 2D seismic; Stage 2 - 800 km of 3D seismic; and Stage 3 - drilling of one exploratory well. At the end of each stage, Petrobras has the right to assess the continuity of the proposed exploration program, and to decide whether or not to remain in the deal. Petrobras will spend approximately US$118 million on the block during the initial five-year exploration term.

The acquisition is part of Petrobras' strategy to broaden potential sources of LNG, according to Marcelo Vertis, Petrobras manager of international mergers and acquisitions, Bloomberg reported. "Petrobras has a strategic drive to look for gas in the Oceania region. Development will be focused on LNG-scale finds," Vertis told journalists in Wellington. In April, Petrobras marked its upstream investment in Oceania by farming in to a gas block offshore Western Australia owned by MEO Australia.