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Great expectations, Part 1

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Oilfield Technology,

Oilfield Technology Correspondent Gordon Cope shows us how North America’s oil and gas sector faces tumult as it responds to huge opportunities and huge challenges.


“May you live in interesting times” is considered a curse in China. In North America, the oil and gas industry finds itself in extremely interesting times, with new sources of oil and gas creating a production renaissance, but, at the same time, widespread opposition. Whether the resurgence becomes a boon or a bane depends on how the sector handles it.

Without a doubt, the hottest play in North America is unconventional shale gas and shale oil. Starting in the early 2000s, explorers in Texas combined horizontal drilling with hydraulic fracturing technologies to economically pry natural gas from the Barnett shale; the formation now produces approximately 5 billion ft3/d. Several other new plays, including the Haynesville shale in Louisiana, the Marcellus in Pennsylvania and the Utica shale in New York have shown equally tremendous potential, and the US Energy Information Administration (EIA) says that shale gas now accounts for 15.6 billion ft3/d, or 26% of all US gas production.

In Canada, the Horn River Basin’s Ordovician Muskwa formation in northwest Alberta and northeast British Columbia has an average of 175 m of pay and over 130 billion ft3 per square mile of gas in place. The Montney basin shale has over 150 m of pay and up to 90 billion ft3 per square mile. These two targets alone hold over 600 trillion ft3 of gas in place.

IHS CERA, a consultancy, estimates that natural gas reserves and resources in North America exceed 3000 trillion ft3; of that, shale gas makes up 1200 trillion ft3 in the US and 500 trillion ft3 in Canada.

A report commissioned by the American Petroleum Institute (API) estimates that the oil and gas industry could spend US$ 5.1 trillion in cumulative capital expenditures on unconventional resources between now and 2035, create 3.5 million jobs, and add more than US$ 2.5 trillion in cumulative added federal, state and local tax receipts.

In addition, explorers have turned to liquids-rich shale. According to the United States Geological Survey (USGS), the Bakken formation in the Williston basin (located beneath North Dakota, Saskatchewan and Manitoba) contains as much as 3.6 billion recoverable bbls Oil production, which stood at 100 000 bpd in 2005, has already exceeded 800 000 bpd in 2013, and the play is still considered in the early stages. The Eagle Ford shale in south Texas is also delivering on its great promise. The formation produces gas, gas condensate and oil, but most activity is currently focused in the oil rich portion. Production has grown from virtually nothing in 2010 to 700 000 bpd by the end of last year.

In Canada, the Alberta Energy Regulator (formerly the ERCB) reported that Alberta’s resources in the Duvernay, Montney and Muskwa formations could top 58 billion bbls of gas liquids and 400 billion bbls of oil. Operators have spent billions of dollars to sew up production rights to a wide swath of land through central Alberta.

The oilsands in northern Alberta hold almost 2 trillion bbls of bitumen (170 billion bbls. of recoverable) trapped in sand and clays. Oil companies have spent tens of billions of dollars to boost production to 2012 levels of 1.9 million bpd (800 000 bpd through surface mining, and 1 million bpd with in-situ, or thermal projects). Recently, operators succeeded in commercial production in the Grosmont formation, a nearby Devonian carbonate also rich in bitumen. There are approximately 400 billion bbls of bitumen in the Grosmont; operators estimate that as much as 100 billion bbls might be recoverable. The Alberta Energy Regulator recently released its latest production estimates, and now expects that, by 2022, oilsands, unconventional and conventional production will rise to 4.2 million bpd.

The Gulf of Mexico has now recovered from the extended exploration hiatus that followed the BP Macondo tragedy. In 2012, production amounted to 1.4 million bpd, and is on track to reach 1.5 million bpd by 2014. Chevron continues to develop the Jack/St. Malo, Big Foot and Tubular Bells fields. The three fields may contain more than 500 million bbls of potentially recoverable oil, and production from the deepwater fields is expected to start in 2014. In addition, Anadarko and partners are on schedule for production in mid-2014 from the 300 million boe Lucius deepwater discovery. The truss spar platform will have a capacity of 80 000 bpd of oil and 450 million ft3/d of gas.

New discoveries continue to emerge in deepwater plays. Noble Energy recently announced that its second appraisal well at the Gunflint field found 109 ft of net oil pay in the Lower Tertiary play, a series of large, anticlinal structures with four-way closure. The trend, which sits beneath a thick wedge of salt, runs from the middle to the western side of the Gulf of Mexico and is about 50 - 70 miles wide and 200 miles long. Estimates issued by the Bureau of Ocean Energy Management (BOEM) indicate that the trend may contain approximately 31 billion bbls of oil and 134 trillion ft3 of gas that are currently undiscovered and technically recoverable.

Off the East Coast of Canada, ExxonMobil and partners recently announced a C$ 1.5 billion engineering, procurement and construction contract with Kvaerner ASA to build a gravity-based production structure for its C$ 14 billion Hebron heavy-oil project in the Grand Banks of Newfoundland. Current production in the Grand Banks amounts to 297 000 bpd. The 1 billion bbl Hebron field is expected to add 150 000 bpd of production over a 30 year period from a gravity-based structure starting in 2017.




Part 2 of this article can be reached here.

Part 3 of this article can be reached here.




Adapted by David Bizley

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