The shale revolution that started in the U.S. is starting to spread around the world. American technology has unlocked production in tight gas and oil and gas shale plays in Canada and the U.S. by using horizontal drilling and multistage hydraulic fracturing.

Shale rock is formed by sedimentation of clay particles in deep waters. When the sedimentation has occurred in waters with limited circulation and lack of oxygen, the shale turns rich in organic content. Deep rifts in the seabed or locked-in seas are favorable for creating organic black shale. If the black shale has consecutively been buried by kilometers of eroded material, and thus been exposed to high temperatures and pressure for a long geologic time, the shale rocks may constitute the source in petroleum systems.

Reserves, Dry-Gas Plays

Economically viable dry-gas resources are shown for a selection of US. and Canadian unconventional plays, including a few recently developed tight-sands plays, as of 2011.

In petroleum terminology, the source rock is referred to as "the kitchen," where oil and gas have been baked out from the initial ingredients of immature organic material. In conventional plays, geologists would also have to look for migration paths for oil and gas to move into permeable and porous reservoir rocks, with structural traps to contain large hydrocarbon volumes, and finally, a leak-proof seal formation to obstruct further seepage. Unfortunately, for most occurrences of shale with an abundance of hydrocarbons, the probability is quite diminutive for all the required geologic events to coincide.

But creative petroleum engineers have found a work-around solution: why not transform the source rock itself into a high-performing reservoir by crunching in-situ the massive and impermeable shale? Why wait for millions of years for migration to happen, and when the result is also highly uncertain? These impatient petroleum engineers deploy hydraulic fracturing (fracturing) in horizontal wells with so much power that the shale cracks from the wellbore and leaves a fracture pattern with a radius of up to several hundred feet, and with a lateral length of several thousand feet, thus transforming a volume of massive shale into a natural gas or liquids-rich reservoir that can be produced.

Rig Count, Shale Gas Plays

Shown are rig counts for selected shale-gas plays.

Environmental concerns have arisen due to a public fear of migration of natural gas or fracing fluids from the ultra-deep shale formations to shallower freshwater aquifers. Although the risk of fractures propagating between separate rock formations seems slight, the burden of proof now lies with the oil and gas industry. It must also be careful to manage the real risks related to surface treatment of fracing fluids, and the potential contact with fresh-water aquifers when the drill bit enters uncased surface rock. However, the latter is not a risk specific to fraced wells.

During 2011, an estimated 5,000 horizontal fraced wells will be drilled into shale formations and contribute to the steepest growth ever of gas production and reserves additions in the U.S. If activity continues at this pace, shale-gas production may reach a level of 10 trillion cubic feet (Tcf) per year within a decade, or close to 50% of the current annual production of natural gas within the U.S.

Dry-Gas Production

Dry-gas production is on the rise for certain U.S. and Canadian shale plays.

This unconventional way of producing gas from shale is not a recent development. Hydraulic fracturing was first performed in 1947 on the Hugoton gas field in Kansas by Stanolind, or Standard Oil Indiana (later Amoco, now merged with BP). And the hydraulic fluid that bolstered productivity of the Klepper #1 well was actually napalm.

Today, the majority of new gas wells in the U.S. are fracture stimulated. The continuously increasing cost competitiveness of shale-gas drilling has brought regional gas prices down to a quarter of the price of oil, measured in Btu equivalents. Companies continued to drill into shale formations during 2009 and 2010, despite the fact that a large share of the new wells had break-even prices below Henry Hub forward prices of around $4. The rationale for this apparently uneconomic behavior was that hedged prices were still relatively high, and inactive leases would expire without at least one productive well. The effect has been an increase in gas output and a further reduction in spot prices, a trend that also accelerated despite underground storage of this new supply being filled up.

Average Break Even

Shown are half-cycle break-even prices (excluding land costs) for selected plays.

As a consequence of the price disparity between gas and oil, companies have shifted focus from dry-gas acreage to wet-gas acreage or to pure liquids plays like the Bakken and Eagle Ford shales. In the tight granitic sands of the Granite Wash play in the Texas Panhandle and Oklahoma, such wells have recently reported up to 10,000 barrels of oil equivalent (BOE) per day of initial production, a rate matching steady-state production rates at world-class giants like Troll Field, off Norway. However, this hunt for liquids does not necessarily help to increase gas prices, because two-thirds of the hydrocarbon from these new "liquids" wells is actually dry gas, bringing even more unwanted gas to the market. But with the potential to supply 800,000 barrels of oil per day to the U.S. market, the macro effect of the emerging tight-oil plays may become significant.

The following excerpt from the North American Shale Quarterly illuminates these trends. The quarterly is produced jointly by Hart Energy and Oslo consulting firm Rystad Energy, and was launched in June 2011.

In the earlier developments of North American shale resources, natural gas received all of the attention. The U.S. is estimated to have more than 100 years of gas supply based on shale resource potential. Although there shouldn't be much contention about the estimated in-place volumes for the shale plays, it will take more development before the actual commercial potential of these resources is revealed. The two potentially largest plays, the Marcellus and Haynesville, are still in early phases of development.

Play Economics, Liquids Resources

Economically viable liquids resources for a selection of U.S. and Canadian unconventional plays are shown, split by liquids types, as of 2011.

The North American Shale Quarterly (NASQ) estimates all of the U.S. and Canadian shale formations, together with newly developed tight-sands formations, hold around 460 trillion cubic feet equivalent of commercial viable gas resources, constituting roughly 16 years of current North American gas consumption (including Mexico). The Marcellus, Haynesville and Montney, the three largest plays, could also have upside in reserve potential with the de-risking of more areas. More mature plays, like the Barnett and Fayetteville, will have less upside potential.

Analyzing the rig counts in different plays reveals activity shifting away from more mature plays, with rig counts declining in the Barnett, Fayetteville and, more recently, the Haynesville. The Marcellus has started to close the rig-count gap with the Haynesville. The Eagle Ford has continued to see a significant amount of gas-related drilling, as most of the gas areas are also liquids-prone.

Rig Count Comparison (Oil)

The Bakken rig count grew through 2010, and the Eagle Ford saw a significant rise in rig counts form the latter half of 2010.

For Canada, drilling in British Columbia is more seasonal, as soft ground during the spring thaw prohibits the use of heavy drilling machinery, thus slowing exploitation. Our research shows rising rig activity in the Montney/Horn River in 2011, but rig activity hasn't returned to the levels seen in the first quarter of 2010. Despite having the most active rigs, Haynesville drilling has been in decline. Its rig count is dropping, marking the beginning of a shift away from held-by-production (HBP)-driven drilling, which has led to high gas-drilling activity despite a supply glut and depressed prices.

Plays like the Eagle Ford, Montney and Marcellus have also seen the establishment of several joint ventures, with international companies coming in and carrying drilling costs, which should maintain or expand activity in these plays. However, for the Eagle Ford, activity may be directed toward the oil-prone area.

Activity is, of course, also driven by the economics of the different plays. Plays like the Granite Wash, Woodford Anadarko and Eagle Ford get more liquids contributions, which improve the break-even prices on an energy-equivalence level.

Liquids Production, U.S. and Canada

Liquids production is shown for U.S. and Canadian shale plays, including selected tight-sands plays. Production is steadily rising, driven by strong oil prices.

As a consequence, the NASQ forecasts different growth rates for dry-gas production in the various shale plays. The more mature Barnett and Fayetteville plays should see production flattening at 2010 levels, while Haynesville growth will flatten during the 2012-2013 time frame as companies hold their acreage by production. The Woodford may see some short-term growth from associated gas in the more liquids-rich areas within the Anadarko Basin. As a result of its apparently superior economics, the Marcellus may continue to grow and eventually become the largest producing shale-gas play. The Eagle Ford should also continue to grow, as the liquids-rich areas can have significant associated gas volumes. Canadian shale development is expected to be driven by the Montney, with slower short-term growth from the Horn River.

With operators optimizing the extraction of gas from shale, the same techniques have also been applied to tight formations holding liquids. The hybrid Bakken shale formation has been targeted for some years now, but more recently the Eagle Ford has received the most attention, with several international companies entering the play through joint ventures, e.g., CNOOC, Reliance and Statoil. In older, mature regions, such as the Permian and Anadarko basins, operators are applying the lessons learned from shale-gas exploration to deeper and tighter formations previously not exploited. Although not all are shale, these formations are being developed in a similar manner.

The NASQ estimates that all of the U.S. and Canadian shale formations, together with newly developed tight-sands formations, hold around 21 billion barrels of oil equivalent of commercial viable liquids resources (including NGLs), which constitutes about 10.5 years of current U.S. consumption. It should also be noted that some of the gas plays also hold significant liquids resources that are mostly NGLs.

North American Liquids Production By Type

Leaving out oil sands, the new liquids supply from tight formations could lead to a slight growth in U.S. and Canadian supply.

Analyzing the activity level reveals a clear shift of overall drilling activity toward liquids-prone plays. This should be no surprise, given the current price differential between oil and gas. The overall oil rig count in the U.S. almost doubled during 2010, and it has kept growing in 2011. The Bakken rig count grew through 2010, and the Eagle Ford saw a significant rise in rig counts from the latter half of 2010. When oil prices hovered around $100 per barrel, most of the tight plays currently being targeted appeared to be economical as long as the liquid content was high. Tight liquids formations have so far mainly been exploited in the U.S. (disregarding oil sands), although the Canadian side of the Bakken has seen some activity.

Production from tight liquids formations could have a significant effect on U.S. liquids supply, with 2020 output possibly surpassing 2 million barrels of oil equivalent per day. As of the first half of 2011, infrastructure issues exist that may slow growth, especially in the Eagle Ford, where major oil pipelines are not expected to be in place before 2012. The Bakken play has relied on rail to some extent to ensure that the produced oil reaches markets. The exact supply potential from more immature plays, such as the Niobrara, remains uncertain. However, given some operators' large land positions, the play could have significant upside.

As long as oil prices remain high, production from tight formations should continue to grow, with the limiting factor being infrastructure, in some plays. Leaving out oil sands, the new liquids supply from these tight formations could lead to a slight growth in U.S. and Canadian supply, making up for the decline from conventional oil reserves.