Fort McMurray has been in the news a lot lately due to the wildfires that ravaged the city and a huge portion of the surrounding area. Prior to that, Fort McMurray would pop up in news articles whenever some celebrity added oil sands development to their environmental crusade and would get up on their soap box without a full understanding of the facts. That being said, it seemed like high time to point out some of the amazing work that is done in oil sands development.
For those unfamiliar with the oil industry and its recovery techniques, the perception can often be that oil reservoirs are vast pools of liquid, surrounded by rock, located far beneath the earth’s surface, like an underground lake of oil that could be recovered from wells like a child drinking from a juice box through a straw. Those in the oil industry know that oil is contained in the pores and fractures of rock formations and that maximizing oil recovery can often be a struggle.
The Canadian Oil and Gas Evaluation Handbook divides recovery into primary, secondary, and tertiary recovery. Primary recovery involves the production of hydrocarbons using the natural energy of the reservoir and/or artificial lift mechanisms. Secondary recovery includes volumes produced as the result of the addition of energy to the reservoir through the injection of water or gas. Tertiary recovery involves hydrocarbon production resulting from methods not classified as primary or secondary recovery, and often includes the injection of fluids or energy not normally present in a hydrocarbon reservoir.
Despite the use of both primary and secondary recovery techniques, conventional reservoirs struggle to exceed 50% recovery of the oil initially in place. For example, the North Sea overall recovery factor is the highest in the world and is estimated at only 46%. If we look to recovery factors in our own backyard, according to pool statistics from the Alberta Energy Regulator (AER), out of more than 12,600 light and medium oil pools in Alberta, the average recovery factor is 11% under primary recovery and 31% from just over 400 pools under waterflood. From heavy oil reservoirs (~10° to 22.3° API), recovery factors drop to an average of 8% from nearly 2,300 pools and 21% from just under 50 pools under waterflood.
Coming from a background of conventional reserves evaluations in the Western Canadian Sedimentary Basin, I was accustomed to seeing that ultimately more than two thirds of the oil was being left behind. Especially in the case of heavy oil reservoirs, where recovery factors were even lower. So when I first got involved in oil sands reserves evaluations, I expected the trend of declining recovery factors with increasing viscosity to continue. Going back to the simplified juice box analogy, moving from light oil to bitumen production is like changing the easy flowing juice to thick molasses. Given this analogy, it’s easy to see how one would expect oil sands recovery factors to be quite low, but surprisingly, this is not the case.
Depending on the depth of the oil sands deposit, bitumen extraction in Alberta is done through either steam based in-situ processes or open pit mining. Steam Assisted Gravity Drainage (SAGD) is the most commonly applied technique for bitumen extraction in the Fort McMurray area oil sands. It was first developed by Roger Butler at the Alberta Research Council in the 1980’s. SAGD involves a pair of horizontal wells, one producer and one saturated steam injector, with the injector drilled several meters above the producer. Steam is injected, heating up the bitumen, which lowers its viscosity and allows it to flow down to the producer well. Average recovery factors from SAGD developments are between 40% and 60%, which rival the recovery factors seen in the world’s best conventional reservoirs. If you aren’t already impressed, wait for the mining story.
In the late 1920’s, Dr. Karl Clark of the Alberta Research Council patented a hot water process to separate bitumen from oil sand. The process mixes water at 35-80 degrees Celsius, crushed ore and sodium hydroxide to separate bitumen from sand and water. The bitumen floats to the top of the mixture as a froth and is skimmed off. This process is the basis of the extraction methods used by Alberta’s oil sands mining operations, which are able to achieve greater than 90% recovery of the bitumen in the oil sand fed to the extraction facilities. The AER monitors recovery factors from the oil sands mining projects in Alberta and within its Directive 82, the AER has set out minimum expectations of 90% when the bitumen grade (weight percent of bitumen in mined oil sands ore) is 11% or greater, and the following equation when the bitumen grade is less than 11%.
Recovery Factor = -202.7 + 54.1 × (bitumen grade) – 2.5 × (bitumen grade)2
With the bitumen grades from Alberta’s oil sands mining projects ranging from 10 to 13%, recovery factors are expected to exceed 88% to meet Directive 82, and in practice, often exceed 90%. These amazingly high recovery factors are certainly far from conventional and highlight the incredible work being done in the Fort McMurray area.
Tim Freeborn holds the position of Vice President at GLJ and has more than 16 years of experience in the evaluation of oil and gas fields in the Western Canadian Sedimentary Basin, with a focus on Coal Bed Methane and surface mineable oil sands and shales. For year-end 2015, Tim was responsible for the evaluation of all of the operating integrated mineable oil sands projects in Alberta for various clients.