In a press briefing held Nov. 1 in Houston, Wood Mackenzie, the Edinburgh, Scotland-based energy consultancy, and Fugro Robertson, a geoscience provider to the upstream oil and gas industry, provided an updated assessment of the Arctic regions as a long-term strategic energy supply source.
Map courtesy of Wood Mackenzie
Their conclusion is that, although the Arctic offers district opportunities for the oil and gas industry, particularly for those who have the appetite for high-risk exploration and leading-edge development solutions, it may not be the long-term global oil supply frontier that could replace maturing production in established regions.
“These findings are disappointing from a world oil resource base perspective,” said lead study author, Andrew Latham, vice president of energy consulting at Wood Mackenzie.
The “Future of the Arctic” study shows only about one quarter of the oil volumes previously assessed in key North American and Greenland basins. Most importantly, it reveals the Arctic to be a gas province, with 85% of the discovered resource and 74% of the exploration potential as gas.
“This oil-gas mix is not ideal because remote gas is often much harder to transport to markets,” explained Latham. “In addition, export and technology constraints are expected to delay production of a large portion of the commercial gas until 2050.”
Wood Mackenzie and Fugro Robertson assessed the Arctic resource potential using detailed geoscience analysis of individual basins and their various petroleum reservoirs using industry data on exploration wells and existing discoveries.
Locally attractive opportunities
“The largest resource plays do not generate the highest return,” noted Simon Frame, senior vice president of Wood Mackenzie and head of the firm’s Houston office. “They tend to be gas-prone and there are constraints in export infrastructure. However, there are economically attractive exploration opportunities that exist locally.”
Three key factors drive the high full-cycle return potential, said Frame:
- Presence of oil over gas;
- Short lead time to production; and
- Proximity to export routes.
Attractive niche opportunities exist in many basins where the breakeven point of the largest fields are much less than the average. Some large oil fields offer development breakeven prices below US$20 per barrel.
Two basins achieve exploration full-cycle returns of greater than 20%. These are the North Slope in Alaska and the Pechora Sea in Russia. These are both oil-prone basins with good access to markets via pipelines and ice-free seas.
Three individual basins have yet-to-find resources of greater than 10 billion barrels of oil equivalent. These are the South Kara/Yamal basin and the East Barents Sea in Russia and the Kronprins Christian basin in Greenland.
Access to opportunities is relatively open across much of the Arctic. All 5 host governments - Russia, Norway, Greenland, Canada, and the US - are broadly in favor of exploration by international or domestic companies. Competition is lower than in other resource plays of comparable scale, in part due to the technical challenges and the high-cost Arctic environment, and no single “pan-Arctic champion” is pre-eminent in operations in the region.
Under the most likely scenario, it is projected that production from the Arctic will contribute some 3 million barrels of oil equivalent (3MMboe) per day liquids and 5MMboe per day gas at peak, with the proportion of production from US basins lower than previously estimated.
“This assessment basically calls into question the long-considered view that the Arctic represents one of the last great oil and gas frontiers and a strategic energy supply cache for the US,” said Latham.
Look elsewhere to meet demand
The findings also indicate that the US must look elsewhere to meet rising demand - namely to OPEC nations such as Venezuela and Russia. Although these supply options are not expected to face long-term technical challenges such as in the Arctic regions, they do carry broader, geopolitical concerns relating to security of supply.
“While these results are disappointing to the US as a whole, the Arctic still holds great potential for individual oil and gas companies with the advanced technology, money, and time to develop the challenging resources and build the infrastructure required to transport it,” added Latham.
Additionally challenging is the Arctic’s resource distribution, which is not expected to alleviate current supply issues. With many of the required technologies still in their infancy, peak Arctic production is not expected for at least 20 years. This means that in the short term, Arctic resources are unlikely to compete favorably with lower-cost sources such as the Middle East. - Don Stowers
Anadarko divests Canadian unit, adds US properties; company starts production in Bohai Bay
Houston-based Anadarko Petroleum Corp. has completed the sale of its Anadarko Canada Corp. business unit to Canadian Natural Resources Ltd. for US$4.24 billion. In addition, Anadarko has agreed to divest its remaining Canadian Arctic frontier assets through a separate exchange of assets with Chevron USA Inc. and Chevron Canada Ltd., both wholly-owned subsidiaries of Chevron Corp.
The transaction with Chevron involves a swap of Anadarko’s interests in the Mackenzie Delta, Beaufort Sea, and the Yukon in return for an incremental 12.5% working stake in 7 deepwater Gulf of Mexico blocks encompassing the Tonga discovery, as well as better terms within the companies’ recently announced West Texas exploration joint venture.
Anadarko, which currently is drilling an offset well to the Tonga discovery, has a 37.5% working interest and intends to accelerate development of the field, potentially as a tie-back to the company’s 100%-owned Constitution production facility.
“These [Canadian] divestitures advance our efforts to refocus the portfolio and reduce debt following our acquisitions of Kerr-McGee and Western Gas Resources in August,” commented Jim Hackett, Anadarko chairman, president, and CEO. “The sale of Anadarko Canada has allowed us to reduce debt by about $4 billion, while the Chevron transaction has provided valuable new interests within our core onshore and deepwater Gulf of Mexico focus areas.”
Bohai Bay
Anadarko has started oil production from the unitized CFD 11-6/CFD 12-1S development project in Bohai Bay, China. The company expects to have 10 wells on line and producing about 15,000 barrels of oil per day during the fourth quarter of 2006. With development drilling continuing, gross production is expected to ramp up to 22,000 barrels of oil per day from 22 wells by mid-2007.
The development project straddles blocks 04/36 and 05/36 in Bohai Bay in about 75 feet of water. The project consists of a core-area gathering platform and two smaller unmanned satellite platforms, which are tied back about 13 kilometers to the Hai Yang Shi You 112 floating production, storage, and offloading vessel.
Anadarko is operator of the unitized development project with a 29.18% interest. CNOOC Ltd. has a 51% interest, Newfield Exploration Co. has a 12% interest, and Ultra Petroleum Corp. has a 7.82% interest. - Don Stowers
Berry Petroleum to develop California diatomite asset
Berry Petroleum Co. will begin commercial development of its Midway-Sunset diatomite oil resource project in California based on the performance of a 2-year pilot program, according to Robert F. Heinemann, president and CEO.
“We have estimated the project has 200 million barrels of oil in place, making it a significant asset for our California operations and for Berry,” commented Heinemann. “The project will add material production and reserves to the company as a part of our growth strategy. Over the next 4 years, we will invest an additional $210 million in capital to drill 520 shallow development wells in the central fairway of the asset and add steam generation and processing facilities.”
Heinemann added, “We expect this development will recover 30 MMbbl and increase production to 7,000 (bbl/d) by 2010. As we develop the fairway, we will also appraise the potential of recovering an additional 15 to 20 million barrels in the outer portions of our acreage in subsequent development phases. We expect the production and reserves from this project will add significant shareholder value throughout the years.”
Michael Duginski, executive vice president of California and corporate development, said, “We began our diatomite pilot with 13 wells in 2004 and have expanded the project. Current production is over 500 bbl/d and the steam-to-oil ratio in the core of our pilot area has declined to 6 to 1.”
Duginski added, “Achieving this level of performance has been key to moving ahead with a development plan. We believe that the central fairway contains 55% of the oil resource and has reservoir properties similar to the pilot. This will enable a repeatable development like those used in our other California assets. We will expand the project in 2007 and will spend about $50 million of capital for 100 wells and associated facilities targeting an average daily production of 1,000 bbl/d for the year.”
G. Timothy Crawford, vice president of California production, noted, “The development of our diatomite asset will leverage Berry’s heavy oil experience. Our drilling performance has improved over the course of the pilot, and this development is well suited for the automated drilling rig we have under contract for the next three years.”
Crawford concluded, “Large resource plays with repeatable development are Berry’s strength, and our team has a phased plan for this asset that will allow us to monitor and improve performance over time. We do not anticipate any environmental or permitting barriers that will delay this project.” - Mikaila Adams
Pluris Energy Group will acquire Argentinian oil and gas company
Houston-based Pluris Energy Group has entered into an agreement to acquire San Enrique Petrolera, an Argentina-based oil and gas upstream and midstream company.
Photo courtesy of Pluris Energy
A Pluris spokesman noted that Argentina is one of South America’s largest and most important economies, adding that Argentina’s oil and gas industry is considered one of the most competitive and efficient in the world. With about 2.7 billion barrels of proven oil reserves and 21 trillion cubic feet of proven natural gas reserves, Argentina is a significant player in the Latin American energy market.
Argentine natural gas production has been on a steady incline and surpassed Mexico in 2000. As oil and gas developments and production have increased, the country has turned from being a gas importer to gas exporter. In 2004, Argentina was the third-largest oil producer in South America at 692,600 barrels of oil production per day, of which 295,600 barrels of oil per day are exported, primarily to Chile and Brazil. More than 5,000 miles of pipelines and thousands of megawatts of new electric power capacity are currently being completed within Argentina to serve the regions energy demands.
Argentina has been among the most progressive countries in South America in privatizing its oil and gas fields, and the business goals of producers in Argentina are similar to those of the US oil and gas community.
Several independents and major oil and gas companies have made significant strides with positioning in Argentina. Chevron Corp., Pan American Energy, Petrobras Energia, and Pioneer Natural Resources have all made substantial investments into the Argentinean oil and gas industry. Recently, Apache Corp. announced its agreement to purchase Pioneer’s interests in Argentina for a reported $675 million.
Areas of development interest for oil and gas players in Argentina lay within the Neuquén, Austral, Golfo San Jorge, Cuyana, and Noroeste Basins. The Neuquén, Austral, and Noroeste basins contain Argentina’s largest proven natural gas reserves. As of 2003, the Neuquén basin held 47% of the countries proven natural gas reserves and accounted for approximately 65% of natural gas production.
Among the petroleum basins of Argentina, the Neuquén Basin is the leading producer of hydrocarbons, with current daily production exceeding 262,000 barrels of oil and 2.7 bcf of natural gas. Total remaining reserves are 1.2 billion barrels of oil (35% of the country’s reserves) and 14 tcf of natural of gas (47%). The 137,000 km2 basin, situated entirely onshore, is part of the SubAndean trend which extends the entire length of South America. San Enrique’s key assets consist of 2,700 net acres located in the Northeast Platform portion of the Neuquén Basin and 65,646 net acres in the southern tip of Argentina’s Tierra del Fuego region situated in the Austral Basin.
To encourage investment in the underexplored Austral Basin in Tierra del Fuego, the Argentinean government has established an income tax and export tax free zone, which makes the fiscal terms for investment very attractive for operators relative to other parts of the world. Total net acreage to all of San Enrique’s property interests currently consists of 251,376 acres.
The San Enrique development interests include proved producing reserves of approximately 2.0 million barrels of oil and 14.6 bcf natural gas with current net production of approximately 1,000 boe/d. Proved, probable, and possible reserves are estimated at approximately 25 million barrels of oil and 142 bcf natural gas, or a total of approximately 49 MMboe.
Pluris said that an aggressive development mandate led by San Enrique’s operator, ROCH, SA, is in place that will see the rapid expansion of the key San Enrique interests in the Neuquén and Austral Basins over the coming 24- to 36-month period.
Pluris Energy’s mandate for entry into the Argentine energy industry is based upon a number of driving factors related to the exceptional business opportunities that exist within the country, coupled with Pluris Energy’s in depth understanding of the region through past experience. This experience includes management’s longstanding history of involvement in the Argentine energy industry in exploration and production, business development, and M&A activity.
