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Feeling the gas crunch North American producers chase deeper targets, forego shallow drilling in bid to combat costs; Western Canada headed for decline in activity through 2014 Gary Park For Petroleum News
EOG Resources is transferring its Canadian natural gas focus from shallow vertical prospects to horizontal shale gas and Apache is moving from shallow conventional and unconventional projects to deeper, higher-return targets.
Those strategic shifts by two of the largest U.S.-based companies operating in Canada are consistent with mounting evidence that drilling in the Western Canada Sedimentary basin is headed for decline as higher field costs erode the economics of increased well counts.
Ziff Energy Group said reduced cash flow from weaker commodity prices in 2006 will carry over this year to a decline in upstream reinvestment.
Officials with the Calgary-based international energy consultant said that not only does it expect a 10 percent drop in gas well completions this year — the industry’s record of 15,700 was set in 2004 — but it estimates development wells will outnumber exploration wells by three-to-one.
Simon Mauger, the report’s lead author, said areas that were analyzed include the impact of gas prices on drilling activity and the drilling outlook through to 2035.
He said the information gathered shows that the full-cycle cost of new conventional gas supply in the Western Canada Sedimentary basin has more than doubled in the last five years to exceed C$8 per thousand cubic feet.
As a result, this new gas, as it comes on stream, will have a negative impact on producers’ profitability.
Deeper prospects targeted To commercialize their book value, producers are being forced to tackle deeper prospects as the opportunities for infill drilling diminish and returns from deeper, higher flow rates become more attractive.
Ziff estimates that the average well depth in the Western Canada Sedimentary basin has increased about 9 percent to more than 3,800 feet, with deep wells now accounting for about one-third of industry activity.
One of the study’s conclusions is that fewer wells will be drilled in the Western Canada basin over the period to 2014-15, before an Alaska pipeline could be completed but after the start-up date for the Mackenzie project.
The picture for Canada, while more extreme in some respects, is mirrored across North America, based on a new report by Cambridge Energy Research Associates, which said increasing costs and shrinking production rates are pinching the margins of producers, regardless of a period of strong commodity prices.
The study underscored the trend in the Western Canada Sedimentary basin, pointing to a dramatic move towards “unconventional” production, which now accounts for 23 percent of output.
CERA, a division of IHS, examined cost and production data for 48,000 wells drilled in all 50 North American basins in 2005 and found that capital costs (excluding operating costs, royalties and returns) ranged from US$1 per thousand cubic feet to more than $6, with the weighted average all-in cost spread from under $4 to over $12.
“Judged against the record prices of 2005, which average $8.80 at Henry Hub, more than 6 percent of basins had costs high enough that they would fail to achieve a 10 percent rate of return-on-investment,” CERA said.
High prices triggered gas drilling High prices, partly the result of Gulf of Mexico hurricanes, triggered a “tremendous response in drilling by gas producers, leading to nearly decade-high reserve additions of 26.4 trillion cubic feet and added production of 14.7 billion cubic feet,” said Michael Bodell, CERA’s director of upstream gas strategies.
But he said the record well completions are being offset by falling per-well productivity.
“The fundamental driver of the North American E&P challenge is the relative maturity of the natural gas resource base. Although gas resources are available — and some are off limits due to access issues — and new plays are being identified and developed, many of these resources are deeper, smaller, technically more challenging or more distant from markets,” Bodell wrote.
The study concluded that E&P companies are generally developing smaller resources and facing higher costs, pushing unit costs up, although many regions offer very strong margins and provide returns on equity well above 10 percent.
However, CERA observed that stepped up drilling levels are needed to replace gas lost from declines in production from wells drilled in previous years, noting that if no drilling had occurred after 1999 North American wet gas production would have fallen to 29 bcf per day in 2006, less than half the output in 1999.
Bodell said CERA was unable to answer the question of whether unconventional gas is cheaper or more expensive than conventional resources.
He said the industry is “investing heavily in unconventional resources moving from the easier plays and basins to resources that represent more challenging opportunities.
“These more challenging resources may come at a cost that has the potential to put them in direct competition with imported LNG,” he said.
Apache lowering spending The response to high service costs has forced Apache to lower this year’s Canadian exploration and development spending to US$700 million from $1.1 billion last year as part of an overall North American reduction of $600 million.
Chief Executive Officer Steve Farris said in a conference call that “service costs have moderated significantly with the reduced commodity prices, but if they don’t stay in line with prices, we and others will reduce our drilling to stay in line with the margins you get between service costs and price.”
For Canada, he said that as Apache evolves to deeper from shallow plays it will concentrate on ExxonMobil farm-in acreage in Alberta, British Columbia and the Foothills of the Canadian Rockies.
He said Apache has acquired 477 square miles of three-dimensional seismic that has targets as deep as 13,000 feet.
Last year, Apache Canada drilled 874 wells with an 85 percent success rate, while Canadian production included a 9 percent increase in gas production to an average 404 million cubic feet per day, although proved gas reserves dropped 103 bcf.
EOG Canadian reserves dipped by less than 1 percent, probably reflecting an overbooking of proved undeveloped reserves from shallow gas acquisitions made a few years ago.
Chairman and Chief Executive Officer Mark Pappa said that if gas prices take a sharp drop, EOG would scale back drilling in Canada, while the Barrett Shale of east Texas and Utah’s Uinta basin would be the last places to experience cuts.
In the meantime, the shift to shale gas drilling, taking advantage of EOG’s expertise in that field, will occur over the next two or three years, he said.
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