The energy and industrial sectors are turning towards hard-to-reach and non-negligible oil reserves that are essential for future energy supply. This is because conventional oil reserves are being depleted and reaching the end of their commercial life. However, commercial extraction of heavy oil poses significant challenges due to its high viscosity and density, particularly in countries such as Canada and Venezuela, where viscosity values can reach up to 10⁶ cp. The primary challenge is to reduce the oil’s viscosity to facilitate easier production of hydrocarbons. To tackle this challenge, thermal methods like steam injection and in situ combustion are employed as effective solutions [1]. While steam injection may seem feasible, it has significant environmental drawbacks, such as requiring vast amounts of water and energy and generating large amounts of greenhouse gases. In contrast, in situ combustion is a promising and less environmentally harmful solution that ignites a portion of the heavy oil in the reservoir while reducing its viscosity and enabling its easier extraction.

Moore et al. [1] define in situ combustion as “the propagation of a high-temperature front for which the fuel is a coke-like substance laid down by thermal cracking reactions”. In other terms, it is a thermally induced enhanced oil recovery method where the thermal energy is generated in situ, i.e., in place or in the reservoir, by injecting an oxidizing gas (air or oxygen-enriched air) that burns a portion of the heavy oil acting like a fuel, i.e., 5 to 10% of the oil-in-place [2]. Typically, this oil is predominantly composed of heavier components.

The in situ combustion method is known to be the oldest thermal recovery method ^[3][4][3,4] dating back to the early 1920s ^{[5][6][7][8][9][10]}[5,6,7,8,9,10]. Since then, many projects have been carried out all over the world. The first successful ISC (in situ combustion) project in the U.S. occurred in 1920 in southern Ohio to melt paraffin and increase oil production [11]. Similarly, the first field experiment of in situ combustion outside of the U.S. took place in the Soviet Union in 1935 [12]. In Canada, Lloydminster-type sands in Alberta and Saskatchewan have good features for implementing fire flooding. To date, the most successful project is located in the Suplacu de Barcău field in northwestern Romania and has become the largest of this type in the world [13].

Over the course of implementing in situ combustion, there have been both successful operations and failures resulting from various factors. Despite demonstrating exceptional theoretical thermal recovery efficiency, multiple projects in the 1990s encountered failure. The causes behind these failures include an inadequate selection of reservoirs, unfavorable characteristics of both the reservoir and the fluid, deficient design and operational practices, and unfavorable economic factors [4]. Specifically, in Canada, problems like the lack of control of the operation are attributed to a poor understanding of the main kinetic parameters [1]. This has led to many early failures in field tests (55% of the projects in the USA between 1960 and 1990 failed) [4]. Consequently, the level of interest in ISC has dramatically decreased, which is why operation and production engineers consider it as their last option for oil recovery [14]. Additional factors contribute to this issue, including the substantial investment required to acquire air compressors, the intricate nature of the combustion process, which demands a high level of specialized expertise, and the scarcity of qualified personnel available to tackle this complex task [15].

Notwithstanding, several advantages are associated with this recovery method, including eliminating steam-related costs, a marked reduction in greenhouse gas emissions, avoiding the need for water recycling processes, in situ upgrading of heavy oil, and avoiding energy-intensive methods further down the production chain. Such benefits make this approach both more environmentally sound and economically viable ^{[16][17][18][19][20][21][22][23]}[16,17,18,19,20,21,22,23]. According to Storey et al. [24], ISC can be used to produce more environmentally friendly energy through the in situ production of hydrogen ^[19][25][19,25] and from the naturally high heat flow of ISC via enhanced geothermal systems ^{[26][27][28][29]}[26,27,28,29].

When it comes to enhancing oil recovery, in situ combustion techniques have received significant interest. Three notable methods in this domain are dry forward combustion, wet forward combustion, and reverse combustion. These techniques involve the controlled ignition of oil within the reservoir to improve oil mobility and extraction. Table 1 provides an overview of the different ISC processes. The following section briefly overviews these techniques, their advantages and limitations, and a practical understanding of how they contribute to ISC practices.

ISC Mechanism	Definition	Applied to	Advantages	Disadvantages
Dry Forward Combustion	Most popular version of ISC. The combustion front is generated in situ. Same propagation direction of injected air and combustion front.	Heavy oil reservoirs.	The combustion provides the formation with a complete burning of formation, leaving the formation hydrocarbon-free.	Limit viscosity reduction to recover hydrocarbons. Low heat is transferred from the combustion front to the downstream zones.
Wet Forward Combustion	Combination of forward combustion and waterflooding. Addition of water or steam in the process.	Thin reservoirs.	Increases process efficiency. Improved heat transfer. Improved sweep efficiency.	Simultaneous co-injection of both water and gas can be challenging.
Reverse	The combustion front is initiated at the production well and moves backward against the airflow.	Reservoirs with low effective permeability.	A significant amount of cracking occurs.	Less upgraded oil is recovered. Spontaneous ignition near the injection well.

2. Dry Forward Combustion

This technique involves the injection of air into a designated injector well, followed by the ignition of oil either through natural means (autoignition) or with the aid of external heat sources (such as electrical or gas heaters). It is worth noting that the accidental ignition of an oil reservoir was initially observed in the 1920s during an air injection operation for pressure maintenance, leading to the discovery of the conventional in situ combustion EOR method [30]. Once the oil ignition occurs, different heat zones are created within the reservoir due to heat and mass transport. These zones give rise to distinct temperature profiles. A combustion front is established among the zones where a portion of the oil (coke) undergoes combustion, generating heat. This heat is then transferred via convection through the water, facilitating oil mobilization. Continuous air injection is employed to sustain the advancement of the combustion front towards the production well, with both the combustion front and the injected air moving in the same direction. In conventional dry forward combustion, the injection of oxygen (air) into the reservoir serves the purpose of igniting the coke, sustaining the combustion front, and displacing the oil towards the production well. This process can be likened to cigarette burning or the glowing hot zone observed in barbecue coals [3].

3. Wet Forward Combustion

In the dry forward combustion mechanism, only oxygen is injected; however, during this process, much of the heat remains in the zone behind the combustion front since the heat capacity of the gas is very low. On the other hand, water can be injected with air to improve the heat transfer forward. To overcome this issue, wet combustion was designed to get some heat to the zone ahead of the combustion front [31].

4. Reverse Combustion

Reverse combustion, also called countercurrent ISC, works like a cigarette [31]. The combustion front is initiated near the production well, and the more is blown into the cigarette (into the reservoir), the more the combustion front moves toward the injector well. At the same time, the oil is displaced toward the production well. This results in the air and the combustion front moving in opposite directions. Although not a very promising technique beyond laboratory tests ^[4][15][32][4,15,32], this method was proposed for high-viscosity oil and tar reservoirs where the hydrocarbons have to flow from hot to cold regions, resulting in reduced mobility and increased flow restrictions. To address this challenge, the method keeps the major portion of the heat between the production well and the mobilized oil. By doing so, this method enables hydrocarbons to flow more efficiently during production, with minimal heat losses. Nevertheless, according to Brigham et al. [3], there are two main reasons why it has not been successful:

1.

The need for high-cost tubulars that can withstand the high temperatures of the produced fluids. Also, reverse combustion generally requires more oxygen than forward combustion; therefore, the costs will be higher.

2.

Some deposits of unburned heavy hydrocarbons will remain in the reservoir. Eventually, these materials will tend to react, and the process will shift to forward combustion.