How oil sands achieved production cost improvements in a low price environment

July 13, 2017


Author: Thomas Liles, Analyst, Rystad Energy

Publisher: Petroleum Economist

Since the oil price collapse in late 2014, Canadian oil sands operators have seen a noticeable reduction in bitumen production costs, both in terms of open-pit mining and thermal in situ projects. Some of these reductions are cyclical in nature, and are further accentuated in US dollar terms given currency effects on the Canadian dollar since 2H 2014. While reductions have been noted across the board, however, some operators have been able to achieve clear, structural cost advantages in a low price environment. This is especially relevant for in situ projects that have exhibited more effective energy usage and efficiency gains in reservoir engineering. This article provides an overview of production cost trends throughout the segment and assesses some of the key drivers behind operating cost reductions, focusing in greatest detail on developments among in situ projects.

From a peak of nearly 20 billion USD in 2014, oil sands operating costs decreased at a compounded annual rate (CAGR) of approximately 17% to 13.8 billion USD 2016. Figure 1 shows 2014-2016 per barrel operating cost developments by extraction method and currency. In situ and mining operations saw opex reductions (CAGR) of about 23.5% and 22%, respectively, with 2016 mining numbers at 23.1 USD/bbl and in situ numbers at 11.6 USD/bbl. Although exchange rate fluctuations somewhat dampened the effect in Canadian dollars, mining projects nevertheless saw compound annual reductions of around 16%, while in situ projects recorded a decline of 14.5%.

Thermal in situ projects provide the clearest indication of structural cost advantages. In contrast to mining projects, which target shallow bitumen deposits extractable by open-pit mining, thermal projects rely on wells and steam injection to coax ultra-viscous bitumen from deeper deposits in place—or “in situ”. Steam-assisted gravity drainage (SAGD), which is the most widely-used in situ recovery method, employs horizontal well pairs. Producers inject steam through an upper well to heat a reservoir to ~350 degrees Celsius and increase the viscosity of the surrounding bitumen, which subsequently drains to a corresponding lower well for extraction to the surface. A certain portion of thermal projects—accounting for approximately 10% of 2016 thermal volumes—use cyclic steam simulation, whereby steam injection and extraction occur through an array of single vertical wells in staggered cycles. Due to the steam-intensive nature of thermal extraction methods and the natural gas required to generate sufficient amounts of steam, operators often cite steam-to-oil ratios (SOR, defined as the ratio of steam generation to bitumen production, or m3 steam / m3 bitumen) as a key metric of project efficiency and cost effectiveness. Generally speaking, SORs at or below 2.5 denote higher efficiency, and thus lower costs on natural gas for steam generation.

Figure 2 highlights in situ cost reductions (USD/bbl) from 2013-2016, split according to a SOR threshold (annual time series) of 2.5. The trend indicates not only an existing structural cost advantage among projects with SORs at or below 2.5 prior to the price collapse; it also illustrates more significantreductions once cost cycling took effect after 2014. Accordingly, from 2013-2016 higher-SOR projects experienced opex reductions (CAGR) of 12% to 15.4 USD/bbl on average, whereas their lower-SOR counterparts achieved reductions of 20% to ~7.1 USD/bbl.

This SOR split is also evident in breakeven oil prices. For producing in situ phases in lower-SOR projects, the average breakeven Brent price currently stands at ~38 USD/bbl, whereas producing assets in higher-SOR projects are over 60% higher at ~55 USD/bbl.

Among in situ projects, six stand out for current and/or historic average annual SORs close to (or below) 2.5. Figure 3 illustrates production cost trends from 2014-2016 for these projects. Five projects achieved production costs in the range of 5.65-8 USD/bbl. Devon Energy’s Jackfish project had slightly higher costs at 8.6 USD/bbl, but still well below the in situ average of ~11.4 USD/bbl.

Average annual SORs are also consistent with the opex trend highlighted above, with the Cenovus-operated Christina Lake project (210.8 kbbl/d sanctioned capacity) consistently achieving a SOR below 2 and 2016 production costs of 5.65 USD/bbl. MEG Energy’s smaller Christina Lake project (60 kbbl/d sanctioned capacity) is also notable, with annual SORs at or slightly below 2.5 and 2016 production costs of 6.3 USD/bbl. CNRL’s Kirby South project (40 kbbl/d sanctioned capacity) saw steep SOR and opex reductions following startup in 2013, while Pengrowth’s Lindbergh project (16 kbbl/d sanctioned capacity) saw a significant SOR/opex drop-off following startup of expansion Phase 1 in 2015. Cenovus-operated Foster Creek (180 kbbl/d sanctioned capacity) has low historical SORs with a slight increase in 2016, which is likely connected to the startup of expansion Phase G in October 2016.

Cost and SOR trends likewise appear consistent with reported engineering innovations. Cenovus-operated projects have made use of infill drilling, using a single horizontal well to target unrecovered bitumen between steam chambers and thus increase recovery factors without additional steam injection. In addition to similar infill drilling, MEG Energy-operated Christina Lake features co-injection of non-condensable gas, which acts as a reservoir cap and helps injected steam maintain higher reservoir pressure over extended periods.

While such clear-cut efficiency metrics are less apparent for mining projects, some operators have been able to maximize production beyond project nameplate capacity, thus boosting performance on production costs in a low price environment. Figure 5 shows 2014-2016 year-on-year percentage decreases in production costs for mining projects. All projects recorded at least a 20% reduction from 2014-2015, with Kearl witnessing the most significant percentage decrease of over 50% (largely due to ramp-up of expansion Phase 2).

Nevertheless, other projects demonstrated cost optimization against the backdrop of production maximization and maintenance deferral. Horizon, which was scheduled for a major turnaround in Q3 2015, deferred turnaround activities to coincide with the startup of Phase 2B in Q3 2016, recording a 2015 yoy opex reduction of 35% and further 2016 reduction of 6%. Q4 saw a significant production ramp-up extending into January 2017, and CNRL’s opex guidance for the year stands at below 20 USD/bbl. Likewise, Syncrude noted 2015-2016 yoy opex reductions of 36.5%, which coincided with record 2016 output often exceeding the facility’s 350 kbbl/d nameplate capacity on a monthly basis (see Figure 6).

Improvements in production opex notwithstanding, egress issues and diluent purchases for in situ projects will continue to present significant additional costs for oil sands operators. Additionally, oil sands projects still remain at the high end of the cost curve. According to data from Rystad Energy UCube, breakeven Brent prices for oil sands assets (currently producing or under development) hover just below 50 USD/bbl, compared to a range of ~33-38 USD/bbl for offshore, conventional, and shale assets. Off course, bitumen supply will continue to increase in the mid- and long-term due largely to major project sanctioning prior to the 2014 price collapse (assuming an implied Brent price of 80 USD/bbl, just under 2.8 million bbl/d could be produced economically by 2020). Nevertheless, production cost competitiveness will continue to be driven by structural improvements and scale. Above all, low-SOR in situ projects demonstrate the clearest structural cost advantage in the segment; any new sanctioning will likely come from such projects in the form of smaller optimization phases, or new in situ techniques that partially displace steam with solvent to facilitate bitumen viscosity. Mining operators have also shown some resilience in terms of production maximization and maintenance deferrals, although if low prices persist, the deferral approach may eventually show limitations due to reliability issues.

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Article Contact

Contact: Thomas Liles, Analyst
Phone: +47 24 00 42 00
thomas.liles@rystadenergy.com

About Rystad Energy

Rystad Energy is an independent oil and gas consulting services and business intelligence data firm offering global databases, strategy consulting and research products.

Rystad Energy’s headquarters are located in Oslo, Norway. Further presence has been established in Norway (Stavanger), the UK (London), USA (New York & Houston), Russia (Moscow), Brazil (Rio de Janeiro), as well as Singapore and Dubai.