Subsurface Migration of Methane From Oil Sands Thermal Recovery Operations

Abstract

The Athabasca oil sands are the largest single deposit of too viscous bitumen on Earth. Depending on the depth of the oil sand deposits, the bitumen is typically extracted using either open-pit mining or in situ operations. Oil sands that are deposited in formations shallower than 75 m are generally extracted using openpit mining operations, while deeper deposits are extracted using in situ recovery methods. In situ extraction methods like cyclic steam stimulation and steam-assisted gravity drainage (SAGD) involve the injection of steam into subsurface oil sands formations typically 150-450 meters deep at high pressures (∼1.2-4 MPa) and high temperatures (180-250°C), which mobilizes the viscous bitumen and allows it to be pumped to the surface (Butler, 1991). In 2019, over 1.6 million barrels of oil were produced daily using in situ methods (Oil Sands Magazine, 2020).In a typical SAGD process, steam is injected into an oil sands formation over a long period of time, often between 8 and 15 years, depending on the characteristics of the oil sands reservoirs. Field and experimental observations have demonstrated that the exposure of oil sands materials to heat and steam over a long period of time leads to aquathermolysis reactions, resulting in the generation of gases that include methane (CH 4 ), carbon dioxide (CO 2 ), hydrogen sulfide (H 2 S), hydrogen (H 2 ), ethane (C 2 H 6 ), and carbon monoxide (CO)

Subsurface Containment of Injected Chemicals during In-Situ Bitumen Recovery from Oil Sands

“…The steam heating of oil sands during the thermal recovery operations leads to aquathermolysis of oil sands and in situ generation of gases such as CH 4 , CO 2 , H 2 S, H 2 , C 2 H 6 , CO, and C3, and exsolution of the originally dissolved methane in bitumen. The migration of these gases during SAGD has been previously studied . Co-injection of solvents (chemicals) has shown promise in reducing the steam required for thermal recovery operation and thus results in less greenhouse gas emissions.…”

“…We consider a two-dimensional cross-section with a vertical thickness of 360 m and a horizontal extent of 670 m, as shown in Figure . The domain length is selected based on the horizontal extent of the gas migration observed in previous simulations . The initial water and gas saturations in the oil sands formation are set to be 0.15 and zero, respectively.…”

“…Permeability (a) and porosity (b) fields of the overlying (overburden) formation were generated using the Sequential Gaussian simulation program. Figure reproduced with permission from ref . Copyright 2021 Wiley.…”

“…As is common, the capillary pressure for the oil sands is assumed to be zero. The capillary entry pressures are selected based on the available data reported in the literature and previously reported sensitivity analyses of the subsurface gas migration . For the flow barriers, the Corey-type relative permeability curves are used.…”

“…In addition, the effectiveness of caprocks or equivalents in containing the injected solvents and in situ generated gases needs to be demonstrated. A recent work evaluated the subsurface migration of methane and other gases from the oil sands thermal recovery operations . The authors found that continuous flow barriers with a permeability of less than ∼1 × 10 –18 m 2 could effectively retain the in situ generated gases.…”