April 2017

Montney operators target condensate-rich windows as oil sands diluent demand grows


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NASWellCube: Database with daily updates of official US & CA well data, covering over 600,000 wells and permits. It contains detailed analysis of well curves, pad drilling, re-frack trends and well economics to provide a complete well by well overview of the North American shale industry. 

NASReport: Consists of monthly insights on industry trends, forecasts (short and medium term) for both production and spending. Detailed analysis of key North American shale plays and operators and a deep-dive into well data for drilling, completion and productivity trends. Delivered electronically on a monthly basis. 

NASCube: A subset of UCube. Database with monthly updates of the US and Canada shale gas and tight oil data for 2000+ acreage positions and 90+ shale plays and sub-plays with NPV estimations and long term forecasts at the asset level. Data derives from Rystad Energy’s global upstream database UCube, with additional information regarding acreage and well data.

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Despite persistently depressed oil prices, high-cost bitumen production from Alberta’s oil sands regions is slated to grow from current levels of approximately 2.2 million bbl/d to over 2.8 million bbl/d by 2020, due largely to major project sanctioning prior to the 2014 price collapse. Since many oil sands operators blend bitumen with lighter “diluents” to meet pipeline specifications for viscosity and density, supply growth from the oil sands will continue to push up western Canadian demand for low-density hydrocarbons. This will particularly affect field condensate and pentanes plus recovered from natural gas processing. Although oil sands diluent demand will outstrip Canadian condensate/pentanes supply for the foreseeable future, the imbalance will all but guarantee a premium for condensate in western Canada. This puts many Canadian shale operators in the liquids-rich areas of the Montney Play at an advantage.

Unconventional bitumen production consists of surface mining and thermal in situ recovery methods such as steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS). The bulk of mined bitumen is upgraded into lighter synthetic crude oil (SCO) that closely tracks WTI prices. Most in situ volumes, however, are blended with condensate to create diluted bitumen, or “dilbit,” which typically has a 70/30 bitumen-to-diluent ratio and trades at a discount to WTI.

Figure 1 shows Canada’s historic and forecasted raw bitumen production by extraction method, as well as Alberta’s historic and forecasted diluent demand. Bitumen production in this example excludes upgraded volumes as well as the ConocoPhillips - operated Surmont and Nexen - operated Long Lake SAGD projects, which use synthetic crude oil as a blending agent to produce “synbit.” Since 2005, demand for condensate-based diluent has grown by nearly 350 percent, in line with increasing in situ production.

Additional condensate/pentanes demand stems from non-upgraded mining projects - Kearl and the upcoming Fort Hills project - which blend mined bitumen with diluent and bypass the capital-intensive upgrading process through a paraffinic froth treatment process.

While bitumen supply has demonstrated steady growth, western Canada has witnessed a growing condensate shortfall over the past decade. Figure 2 shows historic and forecasted lease condensate and pentanes plus production for Alberta and British Columbia. This shortfall will widen to over 400 kbbl/d by 2020 and over 500 kbbl/d by 2025, assuming a 67/33 condensate-to-bitumen dilbit ratio.

Rystad Energy’s NASWellCube data shows a clear trend among Canadian shale players towards increased condensate output, specifically through targeting liquids rich areas of western Canada’s most prolific shale plays. Figure 3 shows the average 30-day initial production (IP) rate - split by light oil content - for horizontal wells brought online in the Montney Play, which accounted for over 50 percent of Canadian shale/tight production and investment in 2016. Higher light oil content categories made up only 25 percent of 30-day Montney IPs in 2014, but increased to over 40% of IP volumes by 2016.

When viewing wells brought online in 2015-2016, Seven Generations leads among the top operators in terms of both IP rates and light oil content. In addition to developing greater lease condensate stabilization capacity, the company has the most aggressive Montney investment program for 2017 (>1 BUSD), centered on the condensate-rich Wapiti area in northwest Alberta. Other operators with established Montney positions, such as Kelt Exploration and Arc Resources, are similarly honing in on condensate-rich windows in northeast British Columbia and northwest Alberta.

In light of growing bitumen production and tight regional diluent market, Rystad Energy expects investment and drilling activity to increase in western Canada’s liquids-rich shale areas. Although Alberta’s oil sands will still rely on U.S. shale plays to narrow the condensate shortfall, many Canadian shale companies are well positioned to contribute to increased local condensate supply.

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