Canada: Robust Resource-Wise, Frail Market-Wise

While energy demand in the developed world seems somewhat stabilized, energy demand from emerging economies in the Asia Pacific Region increases year after year.

All forms of energy will be needed to fuel this economic growth, from oil sands to oil and gas liquids, which are found abundantly in the western Canadian sedimentary basin.

And in eastern Canadian provinces of New Brunswick and Quebec, companies like Junex, Southwestern Energy and Apache are evaluating frontier basins for unconventional resource potential.

Artist’s rendering of the proposed Kitimat LNG facility in British Columbia, Canada. Graphic courtesy of Apache Corp
Artist’s rendering of the proposed Kitimat LNG facility in British Columbia, Canada. Graphic courtesy of Apache Corp

Despite Canada’s abundant conventional oil and gas resources, unconventional resources dominate the country’s total reserves estimates.

Ranked the second largest country in the world by area, Canada is the third largest producer of natural gas and sixth largest producer of crude oil. With the abundant supply of new energy sources that are now possible to exploit via horizontal drilling and multi-stage fracking completion techniques, it’s not surprising that Canada is one of the few developed nations that is a net exporter of energy.

The reserves associated with the Athabasca oil sands alone make Canada the country with the world’s second largest oil resource base (178.1 bbl, EIA 2010). Adding to this, Canada’s energy potential from developed and emerging unconventional gas resources continues to expand due to large capital expenditures for both drilling and land acquisition.

Combine these unconventional gas resources with the ever-growing investment in light oil produced from tight unconventional projects, and Canada will remain a net exporter of energy into the foreseeable future.

Abundant resources, however, do not necessarily guarantee optimal market conditions.

As was the case prior to the construction of the Northern Border Pipeline to export Canadian gas to Chicago and the greater North American market in 1998, Canada’s hydrocarbon resources are becoming stranded by reduced demand and significant price discounts resulting from the recently saturated U.S. market.

Canadian Unconventional Activity

A quick look at activity across the spectrum of Canadian resource plays shows an industry engaged in managing and exploiting the abundant oil and gas remaining to be produced and found.

In a recent announcement Imperial Oil stated that the first phase of its multi-billion-dollar Kearl oil sands project in northeast Alberta is expected to start-up in late 2012. When completed, production is projected to reach upwards of 110,000 barrels of bitumen per day from 5.5 billion barrels of established reserves (ERCB, 2011).

On the land sale front, the province of Alberta has taken in lease payments exceeding $2 billion CAD in the first seven months of 2011 – revenue largely generated from leasing mineral rights in the Devonian Duvernay shale.

For example, Talisman Energy spent $510 million CAD in June for Duvernay shale gas rights, bringing its total Canadian land holdings to 360,000 acres.

Early movers have begun de-risking the play, having drilled a few horizontal multi-stage fractured wells in the Kaybob area of north central Alberta. Initial results of two-five mmcfg/d and 75 bbls/Mcf of natural gas liquids demonstrate the potential of this play. Reports indicate Talisman will begin testing the play before the end of the year (DOB, July 29, 2011).

Resource plays are continuing to mature, with light oil and liquids-rich gas being on the forefront. While gas prices are low, the economics for liquid products are more favorable. All resource plays in Western Canada are now producing about 1 mmboed, 80 percent of which is gas.

Current resource plays span intervals from Cretaceous to Devonian in age:

♦ Cretaceous –There are six basic Cretaceous resource plays in western Canada, with average production over 550,000 boepd, approximately 80 percent gas. These are Bluesky/Gething oil, Cardium oil, Viking oil, Deep Basin gas, Glauconite gas and Nikanassin gas.

♦ Triassic-Jurassic – The four Triassic-Jurassic plays are the Jurassic Amaranth oil sands play of Manitoba and Sawtooth oil play of Saskatchewan, plus the Triassic Montney oil and gas plays of Alberta and British Columbia. Total production is in excess of 400,000 boepd.

Amaranth oil sands have been tested by over 350 horizontal wells drilled and are producing over 14,000 boepd with about 89 percent of the production being gas.

The Montney is by far the most prolific unconventional play in Canada, with a combined production of 380,000 boepd (95 percent gas or 2.2 bcf/d) from very-fine grained dolomitic sandstones and siltstones.

♦Mississippian-Devonian– The five Mississippian-Devonian plays are the shale gas of the Horn River Basin, carbonates of the Pekisko, Slave Point/Swan Hills carbonate oil play, the proven Bakken oil in Saskatchewan plus the breaking Alberta Basin “Bakken” oil play and the recently emerging Duvernay shale play.

Together these plays produce about 100,000 boepd, 15 percent gas.

The Alberta Bakken-equivalent Exshaw shale petroleum system includes the over- and underlying limestone reservoirs of the Banff and Big Valley. These two carbonates are the most likely horizontal drilling candidates.

Over 30 horizontal wells have been drilled to date, but very little public information available to help de-risk this project.

Production numbers from the Bakken in Saskatchewan continues to grow. The apparent success of water-flood pilot wells only enhances the viability of this light-to-medium oil resource. Current production is in excess of 65,000 boepd from 2,800 wells.

The Slave Point/Swan Hills oil play on the flanks of major producing oil fields has largely been de-risked. There have been over 200 wells drilled with current production over 14,000 boepd.

The shales of the Horn River Basin in northeast British Columbia are producing over 90 mmcf/d from about 20 wells. Although the play appears to cover over 1.3 million acres – an area over twice the size of the Barnett Shale play in Texas – development has been negatively impacted by low gas prices and the need for infrastructure.

Market Diversification

Of considerable concern to most Canadian producers is the stranded nature of countrywide resources. Currently, the United States is the only available export market.

This limited access to markets leads to significant commodity price discounts. Every exporter knows that having access to multiple market places is good for market prices and competitiveness.

The authorization by the U.S. Department of Energy to Cheniere Energy in May 2011 granting LNG export capacity has perhaps set a precedent for Canada to follow.

Dec. 9, 2010, Kitimat LNG applied for an export license from the National Energy Board (NEB), which would allow the Kitimat facility when completed to ship natural gas to the Asia-Pacific market.

Nearly eight months later on July 25, the NEB announced that it will consider an application submitted by BC LNG Export Co-operative LLC (BC LNG) for a 20-year license to export up to 1.8 million tonnes of liquefied natural gas annually from Canada to Pacific Rim markets. This application is based on projections that the demand for natural gas in Pacific Rim markets will continue to increase substantially over the next 20 years.

The Kitimat LNG project on British Columbia’s west coast is an important step in developing market diversification for at least one Canadian commodity.

“There are plentiful natural gas supplies and reserves that have created a remarkable opportunity to expand our North American energy trade to other continents,” said Carol Howes, media relations manager for Calgary-based Encana Corp. “The terminal is designed to open up Pacific Rim markets for Canadian gas.

“With our partners, we are all helping to lead a continental push to deliver natural gas exports for the first time from Canada to overseas markets,” she said. “This project will help to expand trade, generate investment and create new jobs and additional government revenues.

“We expect the project will help to advance North America’s natural gas economy to markets where demand is growing and natural gas prices are more closely tied to oil prices.”

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The Tarim Basin is one of the most important hydrocabon-bearing evaporite basins in China. Four salt-bearing sequences, the Middle and Lower Cambrian, the Mississippian, the Paleogene, and the Neogene, have various thickness and areal distribution. They are important detachment layers and intensely affect the structural deformation in the basin. The Kuqa depression is a subordinate structural unit with abundant salt structures in the Tarim Basin. Salt overthrusts, salt pillows, salt anticlines, salt diapirs, and salt-withdrawal basins are predominant in the depression. Contraction that resulted from orogeny played a key function on the formation of salt structures. Growth strata reveal that intense salt structural deformation in the Kuqa depression occurred during the Himalayan movement from Oligocene to Holocene, with early structural deformation in the north and late deformation in the south. Growth sequences also record at least two phases of salt tectonism. In the Yingmaili, Tahe, and Tazhong areas, low-amplitude salt pillows are the most common salt structures, and these structures are commonly accompanied by thrust faults. The faulting and uplifting of basement blocks controlled the location of salt structures. The differences in the geometries of salt structures in different regions show that the thickness of the salt sequences has an important influence on the development of salt-cored detachment folds and related thrust faults in the Tarim Basin.

Salt sequences and salt structures in the Tarim Basin are closely linked to hydrocarbon accumulations. Oil and gas fields have been discovered in the subsalt, intrasalt, and suprasalt strata. Salt deformation has created numerous potential traps, and salt sequences have provided a good seal for the preservation of hydrocarbon accumulations. Large- and small-scale faults related with salt structures have also given favorable migration pathways for oil and gas. When interpreting seismic profiles, special attention needs to be paid to the clastic and carbonate interbeds within the salt sequences because they may lead to incorrect structural interpretation. In the Tarim Basin, the subsalt anticlinal traps are good targets for hydrocarbon exploration.

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The Marcellus Shale is considered to be the largest unconventional shale-gas resource in the United States. Two critical factors for unconventional shale reservoirs are the response of a unit to hydraulic fracture stimulation and gas content. The fracture attributes reflect the geomechanical properties of the rocks, which are partly related to rock mineralogy. The natural gas content of a shale reservoir rock is strongly linked to organic matter content, measured by total organic carbon (TOC). A mudstone lithofacies is a vertically and laterally continuous zone with similar mineral composition, rock geomechanical properties, and TOC content. Core, log, and seismic data were used to build a three-dimensional (3-D) mudrock lithofacies model from core to wells and, finally, to regional scale. An artificial neural network was used for lithofacies prediction. Eight petrophysical parameters derived from conventional logs were determined as critical inputs. Advanced logs, such as pulsed neutron spectroscopy, with log-determined mineral composition and TOC data were used to improve and confirm the quantitative relationship between conventional logs and lithofacies. Sequential indicator simulation performed well for 3-D modeling of Marcellus Shale lithofacies. The interplay of dilution by terrigenous detritus, organic matter productivity, and organic matter preservation and decomposition affected the distribution of Marcellus Shale lithofacies distribution, which may be attributed to water depth and the distance to shoreline. The trend of normalized average gas production rate from horizontal wells supported our approach to modeling Marcellus Shale lithofacies. The proposed 3-D modeling approach may be helpful for optimizing the design of horizontal well trajectories and hydraulic fracture stimulation strategies.

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The Guadalupe Mountains (USA) expose shelf to basin cross-sections of the Permian Capitan depositional system along 70 km of depositional strike, providing an excellent outcrop analog for studying the processes that generate early fractures within carbonate platform strata.

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