Oil sands (tar sands, crude bitumen, bituminous sands) – natural mixture of sand, water and bitumen. Bitumen is oil that is too thick or heavy to flow on its own, making it almost solid at room temperature. 96% of Canadian oil reserves are located in Alberta’s oil sands, representing 10% of total world’s reserves. On average, Albertan oil sands contain 10% bitumen, 85% solid mineral matter and 5% water. Similar to other types of heavy oil, bitumen in Alberta has a high concentration of nitrogen, Sulphur (making the oil sour) and heavy metals.
Oil sands are an important contributor to Canada’s economy. In 2015 the energy sector accounted for $19 billion in annual government revenues, and 533,000 jobs across the country in 2017. Oil sands alone were responsible for 228,000 direct and indirect jobs in 2017. Many were outside Alberta – supporting goods and services are produced everywhere in Canada. In 2017, oil sands injected almost $13 billion into the economy.
At the core of this value creating is bitumen extraction. There are two major methods of extracting crude oil from oil sands deposits: mining, accounting for 20% of total production, and in-situ (or in place), which accounts for 80% of total production.
What is the Mining Extraction Method?
Mining is economically viable only when bitumen is relatively close to the surface, which is true for only a portion of Alberta’s oil sands. Typically, mineable oil sands are less than 50 meters deep, with the cut-off being 70-75 meters. All the mines are located north of Fort McMurray along the Athabasca River, where deposits are not too deep under the ground.
After getting picked up by large shovels and transported to a processing facility, the oil sands mixture is crushed and mixed with water to get pumped into a gravity separation unit. Then it is mixed with diluent or solvent to reduce viscosity and further subjected to gravity separation. Depending on how much bitumen the final mixture contains, it is either upgraded or sold to refineries.
What are the In-Situ Extraction Methods?
Oil sands projects discussed here involve developing deposits buried deep beneath the ground. Therefore, all employ in-situ (in place) extraction techniques. This simply means that bitumen is extracted exactly where it was found, as opposed to first being transported as part of an oil sands mixture, and then separated and processed in a plant. The most common types of in-situ extraction are Cyclic Steam Stimulation (CSS) and Steam-Assisted Gravity Drainage (SAGD).
What is CSS?
Cyclic Steam Stimulation (CSS) requires a single well to be drilled on a deposit. First, high pressure steam is infused into the reservoir to heat bitumen and reduce its viscosity. The process lasts for several weeks. Then oil soaks for another several weeks until actual pumping begins. As bitumen cools down, pumping has to stop, and steam needs to be reinjected. Once bitumen reaches the surface, it is separated from the water, which is reused multiple times. After separation, bitumen is either diluted and sold to refineries or sent to an upgrader facility.
Approximately 40% of the bitumen in Alberta is upgraded to synthetic crude oil. Remaining 60% is diluted with condensate and sold directly to market.
What is SAGD?
Steam-Assisted Gravity Drainage (SAGD) requires two horizontal wells do be drilled about 5 meters apart from each other. Wells are typically 150 to 450 meters deep and extend up to 1,000 meters horizontally. The top well (the injection well) is filled with high pressure steam, heating the surrounding bitumen. Warm bitumen starts liquefying and flowing to the bottom well (the producing well) with the help of gravity. Next steps are identical to the CSS method. Bitumen is pumped up to the surface, where it is separated from the water, which is recycled multiple times. After that, bitumen is either upgraded or diluted and sold directly to refineries.
SAGD is a continuous process, with considerably higher production rates and better bitumen recovery than CSS. Also, it doesn’t affect the landscape as much as mining does. However, it requires greater capital expenditure in the initial phase. While CSS requires a single well, two wells have to be drilled and extended horizontally for SAGD. SAGD tends to provide better economics in most cases, making it a more popular choice. All four projects covered here use SAGD.
Steam to oil ratio (SOR) is a key measure of efficiency of SAGD-based operations. It is the amount of steam needed to produce one barrel of oil. Lower ratio suggests more cost- efficient production and lower environmental impact. SOR of 2 implies that two barrels of steam are required to produce one barrel of oil.
Cogeneration capacity is another important factor in evaluating efficiency. Electricity that is used to power oil sands operations is generally produced by burning natural gas. Steam used in SAGD operations is also produced by burning natural gas and heating water.
Cogeneration combines the two processes that require the same input, helping drive the costs down. Excess electricity is sold to electrical grids for personal and commercial use, resulting in more economic benefits.
Well conformance is an additional factor used to assess efficiency. Conformance is a measure of uniformity of the steam front during steam injection in a SAGD operation. Higher conformance improves oil recovery and allows for longer horizontal wells.
Another major method of improving efficiency is use of solvents that are injected into the well together with steam, or replace it altogether (in that case, it is considered a separate technique). Solvents allow for reduced SOR, making it a more cost-efficient process and reducing environmental impact. Also, higher well production rates can be achieved as oil recovery improves.
Major Oil Sands Projects
Cenovus Foster Creek
Cenovus Foster Creek began operating in 1996, becoming the first commercial SAGD oil sands project in 2001. It used to be operated as a joint venture between Cenovus and ConocoPhillips until Cenovus assumed full ownership in May 2017 as a result of an acquisition announced in March the same year. Foster Creek’s current capacity is 180,000 barrels of oil per day, regulatory approved capacity – 295,000. Because the oil is located about 450 meters below the surface, it can’t be mined and, therefore, is extracted using SAGD.
Q1-2018 bitumen production – 157,390 bbls/d. Average realized price – $39.29/bbl, royalties – $3.17/bbl, transportation and blending costs – $8.93/bbl, and operating costs – $10.51/bbl, resulting in a netback of $16.68/bbl. Accounting for realized risk management loss of $(13.53), netback was $3.15.
Q2-2018 bitumen production – 171,079 bbls/d. Average realized price – $54.08/bbl, royalties – $9.14/bbl, transportation and blending costs – $7.54/bbl, and operating costs – $8.75/bbl, resulting in a netback of $28.65/bbl. Accounting for realized risk management loss of $(19.54), netback was $9.11.
Cenovus Foster Creek technical details: 2,607 MMbbls (millions of barrels) 2P (proved and probable) reserves. 9° – 11° API gravity (measure of how heavy oil is compared to water) of bitumen and 22° of final diluted mixture. 3.8% Sulphur content. 2.5 SOR. 25-30 meters net pay. High permeability of 5-10 darcies. High oil saturation of 80%. 98 MW cogeneration capacity. 544 bbls/d average production per well. 2018 forecasted total production is 166,000 bbls/d.
Cenovus Christina Lake
Christina Lake is the second producing project owned by Cenovus. Construction began in 2000, with first production in 2002. Oil is about 375 meters underground, so it is extracted using SAGD. Current capacity is 210,000 bbls/d, regulatory approved capacity – 310,000.
Phase G expansion will add 50,000 bbls/d of capacity by 2021. Steam to oil ratio is expected to be within the range of 1.8 to 2.2. Production is expected to begin in the second half of 2019.
Q1-2018 bitumen production – 202,276 bbls/d. Average realized price – $30.20/bbl, royaltie – $0.59/bbl, transportation and blending costs – $4.78/bbl, and operating costs – $7.38/bbl, resulting in a netback of $17.45/bbl. Accounting for realized risk management loss of $(13.99), netback was $3.46.
Q2-2018 bitumen production – 218,299 bbls/d. Average realized price – $48.74/bbl, royalties – $1.84/bbl, transportation and blending costs – $4.95/bbl, and operating costs – $6.22/bbl, resulting in a netback of $35.73/bbl. Accounting for realized risk management loss of $(19.08), netback was $16.65.
Cenovus Christina Lake technical details: 2,759 MMbbls 2P reserves. 7.5° – 9.5° API of bitumen and 22° of final diluted mixture. 3.8% Sulphur content. 2.1 SOR. 40 meters net pay. High permeability of 5-10 darcies. High oil saturation of 80%. 100 MW cogeneration capacity. 1,140 bbls/d average production per well. 2018 forecasted total production is 207,000 bbls/d.
MEG Christina Lake
MEG Christina Lake, the other major oil sands project located around Christina Lake is 100% owned and operated by MEG Energy, a pure play oil sands Canadian company. First production began in 2008, and currently it is MEG’s only operational property. Located 150 km south of Fort McMurray in close proximity to Cenovus Christina Lake project, it covers 200 sq km. Current capacity – 80,000.
There is a 2-year technology-based growth initiative project underway that started in 2017, which is expected to add a total of 20,000 bbls/d of extra capacity. The expansion is based on MEG’s patented eMSAGP (enhanced Modified Steam and Gas Push) technology. In addition to injecting steam into the well, non-condensable gas, like natural gas, is introduced into the well. This practice helps keep the pressure consistently high, even at lower temperatures. As a result, MEG uses less steam to extract the same volume of bitumen, keeping its SOR as low as 1.3, while also improving recovery.
Combined with eMSAGP additional capacity, 13,000 bbls/d Phase 2B expansion will result in a total capacity of 113,000 bbls/d by 2020. Regulatory approved capacity – 210,000 bbls/d.
MEG has a contract for 50,000 bbls/d of Flanagan South and Seaway pipeline transportation capacity, which will double to 100,000 bbls/d in mid-2020. Approximately two-thirds of the company’s forecast blend sales volume will, therefore, be moved to the Gulf Coast where MEG can realize world pricing.
Q1-2018 bitumen production – 93,207 bbls/d, with total bitumen sales being 91,608 bbls/d. To get bitumen to a marketable condition, it is diluted with purchased diluent. Sales are net of that amount.
In Q1-2018 Company reported $20.16 in cash operating netback. Based on bitumen realization price of $35.31, transportation costs of $5.99, royalties of $1.03, non-energy operating costs of $4.55, energy operating costs of $2.64, power revenue of $1.21 (revenue from electricity sold as a result of cogeneration, which offsets operating costs), and realized loss on commodity risk management of $2.15.
Q2-2018 bitumen production – 71,325 bbls/d, with total bitumen sales being 74,418 bbls/d. To get bitumen to a marketable condition, it is diluted with purchased diluent. Sales are net of that amount.
In Q2-2018 Company reported $18.53 in cash operating netback. Based on bitumen realization price of $47.20, transportation costs of $8.28, royalties of $1.64, non-energy operating costs of $5.47, energy operating costs of $1.79, power revenue of $1.62 (revenue from electricity sold as a result of cogeneration, which offsets operating costs), and realized loss on commodity risk management of $13.11.
MEG Christina Lake technical details: 2.3 billion barrels of 2P reserves. 22° final blend API. 3.9% Sulphur content. 2.2 SOR.
While Suncor is a big player in the mining sub sector, it also operates in-situ projects in the Athabasca oil sands. Suncor Firebag, with production capacity of 203,000 bbls/d is the second largest oil sands project after Cenovus Christina Lake. First oil was produced in 2004, the project is 100% owned and operated by Suncor.
Suncor Firebag technical details: 194,039,385 sq m approved project area. 29.62 m2 continuous reservoir thickness. 0.32 porosity. 0.71 oil saturation. Bitumen is sold to market as Borealis Heavy Blend (BHB) (21.5° API and 3.8% sulphur) or upgraded at a Suncor upgrading facility. 2,595 MMbbls of 2P reserves. 2.7 SOR.
Q1-2018 bitumen production – 205,800 bbls/d.
Q2-2018 bitumen production – 201,900 bbls/d.
CNRL Kirby South
Kirby South is the latest Canadian Natural Resources (CNRL) project, 100% owned and operated by the company. Began operating in 2013, current capacity is 40,000 bbls/d. It is the only CNRL’s SAGD facility, with all the other projects being either mining or CSS-based. The next development, Kirby North, was fully reinitiated in late 2017 after being deferred in 2015 due to low oil prices. It is expected to produce first oil in Q1 2020, with targeted additional capacity of 40,000 bbls/d.
Kirby South technical details: Oil is sold as WCS and Cold Lake Blend (CL). 21° API, 3.7% sulphur. 19.7 m average pay thickness. 76.6% average oil saturation. 33.5% average porosity. 54,000 e3m3 OBIP (original bitumen in place). 27,530 e3m3 DBIP (developable bitumen in place). 16,518 e3m3 ultimate recovery. 5,937 e3m3 cumulative oil produced. 21.5% RF (recovery factor). 2.5 SOR.
Q1-2018 bitumen production – 36,986 bbls/d.
Q2-2018 bitumen production – 35,322 bbl/d.