Levering LNG
The case for replacing diesel with natural gas for oilsands mining fleets
Before the North American shale revolution, Alberta’s abundant natural gas supplies had a steady customer in U.S. markets. But now, horizontal drilling and hydraulic fracturing have increased U.S. oil and gas supplies and depressed prices by allowing for production from large, previously inaccessible shale deposits.
With few near-term prospects for new export markets, Canadian gas producers must find alternative end uses, such as diesel replacement. Diesel, on an energy intensity basis, is much more costly than natural gas. Thus high-diesel users can achieve considerable fuel savings if they run their vehicles on natural gas.
Mineable oilsands operations fit well as a niche model. There is a well-established gap between bulk pricing for diesel on the Gulf Coast versus Alberta, where diesel commands a US$10/bbl premium on average. Also, oilsands mining sites consume large amounts of diesel—typically over 100,000 gallons per day—within a very small geographic area. This minimizes the necessary infrastructure changes and provides significant fuel savings to the operation.
To properly evaluate the suitability of liquefied natural gas (LNG) to feed mineable oilsands operations, a case study was performed. The hypothetical mining project’s battery limit included 40 heavy haul trucks and five heavy lift shovels, which consumed 2,000 bbls/d of diesel. The full-cycle capital expenditure for replacing diesel with LNG included the cost of the micro-LNG plant, refuelling stations and engine modifications. For all the scenarios considered, the cost of natural gas was fixed at US$3.3/mmBtu, which is the long-run average AECO price since 2010. For the base case, Alberta’s long-run average diesel-gas price ratio of seven was used.
Economic model results showed a very attractive after-tax rate of return of 32 per cent and a payback period of three years. Upon applying a 10 per cent discount factor, a net-present value of US$143 million was calculated. Some sensitivity analyses were also performed, which showed that the LNG route is robust enough to withstand changes in Alberta diesel-to-gas prices as well as the potential cost increases in implementing the project.
The fuel substitution percentage also required a sensitivity analysis. Dual fuel engines offer a replacement rate of up to 70 per cent, but they run entirely on diesel while idling and at low RPM. Therefore, the actual overall amount of diesel replacement is dependent upon truck movements and the mine topography. Also, as the diesel replacement changed, so too did the size of the LNG plant producing it. Moving to lower diesel substitution rates was partially mitigated by reduced plant size.
This analysis shows that the project would still be profitable with lower diesel substitution rates (see graph), but higher substitution rates would dramatically improve the project. So would use of high-pressure direct injection engines, which have yet to be commercialized.
Curiously, LNG adoption has not begun despite such compelling arguments in its favour. It may be that operating companies do not wish to distract their core business with LNG production, are understandably adverse to a full-site adoption model or are hesitant to move ahead with large projects in a low-cost environment. However, these issues can be addressed through an over-the-fence business model.
This model actually works very well in the oilsands as there are several mining operations close toFort McMurray. There is potential demand for over one million gallons per day of diesel in the region. To replace 50 per cent of this diesel demand by adopting dual fuel engines will require a centralized LNG plant with a production capacity of close to one million gallons per day, which could be financed, constructed and operated by a third-party LNG supplier leveraging economies of scale. In the base case economic scenario, 70 per cent of the capital required for the project was directed towards designing and building the LNG facility. Removing this from the oilsands operators’ costs offers considerable savings on upfront capital.
This would also allow for a pilot trial first. In performing some preliminary calculations with this model—assuming five per cent regional diesel replacement in the first year, 15 per cent in the second and 50 per cent in the third—even the economics associated with the pilot stage are highly positive. The plant would be paid for in five years, and the oilsands operators would recover the cost of converting their trucks and installing fuelling stations in less than three years.
https://www.oilsandsreview.com/index.php/oilsands-news/columns/11431-levering-lng
