dry combustion, Oil & Gas Glossary

Dry combustion is an in-situ combustion (ISC) enhanced oil recovery (EOR) technique in which only air, or oxygen-enriched air, is injected into a heavy-oil or bitumen reservoir to ignite and sustain a moving combustion front that mobilizes residual hydrocarbons toward producing wells. The technique works by burning a small fraction of the in-place hydrocarbon, typically 5 to 15 percent of the original oil in place (OOIP), to generate temperatures of 400 °C to 650 °C (752 °F to 1,202 °F) in the burning zone. This thermal pulse cracks heavy hydrocarbons via pyrolysis, reduces oil viscosity by several orders of magnitude, and propagates a coke-rich combustion zone that sweeps upgraded oil ahead of it. In contrast to wet combustion, where water is co-injected to recover heat from the burned zone, dry combustion relies solely on gas-phase oxidation without an aqueous quench, which simplifies surface equipment but creates significant downstream gas-handling challenges. The technique was field-tested extensively in the WCSB during the late 1970s and 1980s, with notable trials by Imperial Oil in the Battrum field, Murphy Oil at Eyehill Creek, and Mobil at Marguerite Lake. WCSB heavy-oil targets such as the Lloydminster, Bonnyville, and Cold Lake areas were considered prime dry-combustion candidates because the bitumen viscosity at original reservoir conditions exceeds 50,000 cP at 15 °C, and the Mannville Group sands offer porosities of 28 to 32 percent and permeabilities of 1 to 5 darcies that support sustained air injection rates of 50 to 200 e3m3/d (1.8 to 7.1 MMcf/d) per pattern. The combustion front advances at 0.05 to 0.3 m/day, and a typical inverted five-spot pattern in a 20-acre spacing requires 18 to 36 months for breakthrough of the combustion gas at producer wells. The principal drawback, as the SLB Oilfield Glossary notes, is the highly corrosive and noxious combustion product gases: produced gas streams contain 4 to 12 percent CO2, 0.5 to 4 percent CO, 200 to 2,000 ppm H2S, 100 to 800 ppm SO2, and trace concentrations of mercaptans and oxides of nitrogen. These streams attack carbon-steel flowlines via sweet and sour corrosion, require NACE MR0175/ISO 15156 compliant materials throughout the production train, and demand sour gas treatment trains with amine sweetening, sulfur recovery (Claus units), and tail-gas treatment to meet AER Directive 060 emission limits. Air injection compressors in dry combustion projects are large reciprocating units delivering 100 to 200 e3m3/d at injection pressures of 7 to 14 MPa (1,015 to 2,030 psi), costing CAD 25 million to CAD 60 million per pattern installed, which is the primary reason dry combustion remains a niche technique despite its high recovery factors of 50 to 70 percent of OOIP, well above primary recovery of 5 to 12 percent in Lloydminster heavy oil.

Key Takeaways

Air-only injection mechanism: Dry combustion injects atmospheric air or oxygen-enriched air at 7 to 14 MPa (1,015 to 2,030 psi) into the formation, sustaining a combustion front at 400 to 650 °C that burns 5 to 15 percent of OOIP as fuel. No water is co-injected, distinguishing it from wet or super-wet combustion variants and simplifying surface plant design while concentrating combustion heat at the burn face.
WCSB heavy-oil applicability: Lloydminster, Bonnyville, and Cold Lake Mannville sands with 28 to 32 percent porosity, 1 to 5 darcy permeability, and bitumen viscosity above 50,000 cP at 15 °C are textbook dry-combustion targets. Imperial Oil's Battrum and Murphy Oil's Eyehill Creek pilots in the 1980s demonstrated recovery factors of 50 to 70 percent OOIP, far exceeding the 5 to 12 percent typical of cold heavy oil production.
Toxic and corrosive gas products: Combustion gas contains 4 to 12 percent CO2, 0.5 to 4 percent CO, 200 to 2,000 ppm H2S, 100 to 800 ppm SO2, plus mercaptans and NOx. All downhole tubulars, surface flowlines, and processing equipment must meet NACE MR0175/ISO 15156 sour-service requirements, and the project must include amine sweetening, Claus sulfur recovery, and tail-gas treatment to satisfy AER Directive 060 emission limits.
Capital intensity drives economics: A single inverted five-spot pattern with 20-acre spacing requires a CAD 25 million to CAD 60 million air-injection compressor station delivering 50 to 200 e3m3/d (1.8 to 7.1 MMcf/d), plus sour-gas processing capacity. Operating costs run CAD 18 to CAD 35 per barrel of incremental oil, competitive with SAGD only when WTI exceeds CAD 80 per barrel and gas prices remain elevated.
Regulatory and HSE constraints: AER Directive 051 (injection and disposal wells), Directive 060 (upstream petroleum industry emissions), and Directive 056 (energy development applications) govern dry-combustion projects in Alberta. Pre-project applications require ERCB-style review of injection profiles, sour-gas dispersion modeling under CSA Z662 and ERCBH2S, and detailed emergency response plans for H2S and SO2 release scenarios.

Combustion Front Dynamics and Coke Formation

The combustion front in a dry ISC project is a thin reaction zone, typically 0.3 to 1.5 m wide, where injected oxygen reacts with coke deposited by upstream pyrolysis of heavy ends. The fuel for sustained combustion is not the original crude oil but the coke residue (8 to 15 percent of OOIP by mass) left behind after lighter fractions evaporate and crack ahead of the burn. Oxygen utilization typically reaches 90 to 99 percent at the front, with air-to-oil ratios of 250 to 400 e3m3 of air per cubic metre of oil burned. Combustion-tube laboratory tests at the University of Calgary and Imperial Oil's Sarnia research center calibrate field design parameters by measuring fuel availability, air requirement, and front velocity for site-specific Mannville sand cores.

Pattern Design and Producer Configuration

Dry combustion patterns in the WCSB historically used inverted five-spots with central air-injector wells and four corner producers on 20-acre (8.1 ha) spacing. Vertical wells are preferred over horizontals because gravity override of the gas front is severe in highly permeable Mannville sands, and verticals allow stagewise pressure control. Producers are equipped with steel temperature surveys at 5 m intervals to track the combustion front, and gas-phase chromatography sampling every 7 days confirms front position via CO2/CO ratio and N2 enrichment. Imperial's Battrum pilot ran 12 inverted five-spots over 14 years from 1979 to 1993 before economics drove conversion to cyclic steam stimulation.

Fast Facts

The Suplacu de Barcau dry combustion project in Romania, in continuous operation since 1964, is the world's longest-running and most successful ISC project with cumulative production exceeding 50 million barrels and recovery factors above 55 percent of OOIP. In the WCSB, no commercial dry-combustion project survives today; the technique was largely abandoned in favor of SAGD and CSS during the 1990s once steam-based recovery proved more controllable and produced cleaner gas streams that did not require sour-service infrastructure costing CAD 80 to CAD 200 per installed flowing barrel of capacity.

Dry combustion is one mode of In-Situ Combustion, sitting alongside wet and super-wet variants that differ only in water co-injection strategy. The technique is a sub-category of Thermal Recovery, which also includes steam-based methods such as SAGD and cyclic steam stimulation. The produced sour gas requires processing as Sour Gas due to high H2S and SO2 content, driving the requirement for amine sweetening trains and Claus sulfur recovery units that dominate the surface facility cost stack.

Real-World WCSB Scenario: Murphy Oil Eyehill Creek Pilot

Murphy Oil operated the Eyehill Creek dry combustion pilot in the Lloydminster heavy-oil belt of Saskatchewan from 1983 to 1991, targeting Mannville Sparky sands at 525 m depth with 12° API oil at 8,400 cP. The pilot injected 110 e3m3/d (3.9 MMcf/d) of air per pattern at 9.3 MPa across four inverted five-spots on 20-acre spacing, with total project capital exceeding CAD 90 million in 1985 dollars. Recovery factor reached 58 percent of OOIP across the burned pattern area, producing 1.2 million barrels of upgraded oil at an average API gravity of 18° (compared to 12° original). Produced gas averaged 8 percent CO2, 1.2 percent CO, and 1,400 ppm H2S, requiring a 25 e3m3/d amine sweetening unit and a 4 t/d Claus sulfur recovery train.

The project was shut in when oil prices collapsed to USD 12 per barrel in 1986 and operating costs reached CAD 28 per barrel against a CAD 16 netback. The pilot validated dry combustion mechanics for WCSB Sparky sands but proved uneconomic against the rising SAGD and CHOPS techniques that followed, and no commercial-scale dry combustion project was ever built in the WCSB.