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In-situ combustion

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In-situ combustion is the oldest thermal recovery technique. It has been used for more than nine decades with many economically successful projects. In-situ combustion is regarded as a high-risk process by many, primarily because of the many failures of early field tests. In-situ combustion (ISC) is a displacement process in which an oxygen-containing gas is injected into a reservoir where it reacts with crude oil to create a high-temperature combustion zone that generates combustion gases and creates a heated front that propagates through the reservoir. In-situ combustion (ISC) is an Enhanced oil recovery process for heavy oil in which an oxygen-containing gas is injected into a reservoir where it reacts with crude oil to create a high-temperature combustion zone that generates combustion gases and creates a heated front that propagates through the reservoir. The most common fluid injected is air but there are some cases in which oxygen enriched gas or air is injected. In situ combustion (ISC) is applied as one of the oldest methods of enhanced oil recovery process in petroleum industry. Heavy oil is suppressed in naturally fractured reservoirs in many places around the world and might possibly provide to the world’s energy supply. The most common fluid injected is air but there are some cases in which enriched oxygen gas or air is injected. Enhanced oil recovery (EOR) techniques are needed when unfavourable conditions such as heavy-oil, high IFT, low matrix permeability, oil wet matrix and poorly connected fracture network exist in an oil reservoir.  EOR processes can be divided into thermal and non-thermal recovery processes and ISC is a thermal process.  It has some advantages over steam injection including higher thermal efficiency, relatively small heat loss to the overburden, no heat losses in the wellbore, and it can be applied in deeper and high-pressure reservoirs. On the other hand, ISC can generated severe corrosion, toxic gas production, and gravity override and can be hard to control within the reservoir.  There are two major of the in-situ combustion process namely,  Reverse combustion & Forward combustion.

The process has some advantages over steam injection including higher thermal efficiency, relatively small heat loss to the overburden, no heat losses in the wellbore, and it can be applied in deeper and high-pressure reservoirs. On the other hand, ISC can generated severe corrosion, toxic gas production, and gravity override and can be hard to control within the reservoir.  In general, there are two variations of the in-situ combustion process which are the Reverse & Forward combustion. Most of those failures came from the application of a good process to the wrong reservoirs or the poorest prospects. The objective of this page is to describe the potential of in-situ combustion as an economically viable oil recovery technique for a variety of reservoirs.

For a more complete review, the work of Sarathi,[1] Prats,[2] and Burger et al.[3] should be consulted.

Process description

The process is fuel dominant, where the ignition takes place as quickly as the fuel is absorbed by the oxygen present in the injected air. The amount of heat generated in reservoir is to hold up the combustion process. It is believable that for free oxygen escaped is because of the channellings with which many corrosion problems could be predicted. For the injection of air/water into the reservoir requires to study and understand the reservoir and its parameters like the oil viscosity, fuel, combustion parameters. Using a combustion or oxidation tube as in injection well for injection and production well for fluid production. Most heavy oil reservoirs cannot be produced by conventional methods due to the high viscosity of the oil which is typically in the hundreds to thousands to tens of thousands of cP. In typical practice, for extra heavy oil which has viscosity in the hundreds of thousands to millions of cP, thermal recovery methods such as ISC are used to recover to oil. For heavy and extra-heavy oil, in-situ combustion method is a fire flooding process applied as an enhanced oil recovery method to recover oil from the reservoir. In-situ combustion method is practically possible phenomenon method which is present in oil and gas industry over years. In combustion process air/water is injected in the reservoir through an injection well at desired rate of injection, where the combustion reaction takes place which increases the temperature near the combustion zone resulting in  reduction in oil viscosity with increase in the production. In-situ combustion is basically injection of an oxidizing gas (air or oxygen-enriched air) to generate heat by burning a portion of resident oil. Most of the oil is driven toward the producers by a combination of the following:

This process is also called fire flooding to describe the movement of a burning front inside the reservoir. Based on the respective directions of front propagation and air flow, the process can be either of the following:

  • Forward (when the combustion front advances in the same direction as the air flow)
  • Reverse (when the front moves against the air flow)

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Reverse combustion

This process has been studied extensively in laboratories and tried in the field. The idea is that it could be a useful way to produce very heavy oils with high viscosity. In brief, it has not been successful economically for two major reasons.

  1. Combustion started at the producer results in hot produced fluids that often contain unreacted oxygen. These conditions require special, high-cost tubulars to protect against high temperatures and corrosion. More oxygen is required to propagate the front compared to forward combustion, thus increasing the major cost of operating an in-situ combustion project.
  2. Unreacted, coke-like heavy ends will remain in the burned portion of the reservoir. At some time in the process, the coke will start to burn, and the process will revert to forward combustion with considerable heat generation but little oil production. This has occurred even in carefully controlled laboratory experiments.

Reverse combustion was developed as a method for recovery of very heavy oils which are so viscous that they cannot be produced by any conventional methods.

In these systems, the oil viscosity prevents flow of oil under reservoir conditions. The combustion is initiated at the production well and moves counter to the direction of the air flow. This implies that the air needs to travel from the injector well through the cold reservoir to find the combustion front. Reverse combustion has been tested in the laboratory and some field applications have been reported in the literature. The primary problem for reverse combustion processes is that the oil tends to ignite near the injection well. The process is difficult to apply to commercial project because spontaneous ignition around air injection wells cut off oxygen supply. Huge amount of oxygen is required to generate the combustion front compared to the forward combustion, which results in increased project operating cost.

For a more complete review, the work of Sarathi,[1] Prats,[2] and Burger et al.[3] should be consulted.

In summary, reverse combustion has been found difficult to apply and economically unattractive.

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Forward combustion

The frequently tied-down method for heavy and extra heavy oils, to transform the heavy and extra-heavy oil into less viscous fluids. It is a rapid method of thermally recovery of oil.  The chemical reaction between the oil and injected air generates the heat which is depended on the oil matrix system. The combustion reaction is slow enough to allow the flow of free oxygen to increase the thickness of combustion zone. At desired rate of injection in low permeability reservoirs both water and air cannot be injected at the same time.  It can be done alternatively, and injection rate/time can be controlled to obtain at the required average air/water ratio at the required combustion front velocity and the temperature level. At high air/water ratio, water covers most of the liquid phase by reducing the maximum temperature. On the other hand, for low air/water ratio, the water that reaches the combustion zone is converted into steam. The generated heat from the combustion zone can reduces the viscosity, increases the recovery and production rate of oil. [4]

Because only forward combustion is practiced in the field, we will only consider this case. Forward combustion can be further characterized as either of the following:

  • “dry,” when only air or enriched air is injected.
  • “wet,” when air and water are co-injected.

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Dry combustion:

In dry combustion only air is injected into the reservoir and energy is generated due to the combustion between oxygen and the crude oil in the reservoir. Generated heat increases the mobility and decreases the viscosity of oil. Generally heavy oil has high viscosity along with low API gravity which leads to a very low primary recovery. During the combustion, the effects of geological parameters play’s a crucial role in controlling the effectiveness of the reservoir.  Oil recovery increases due to two major reasons: 

1.       A steam zone is formed near the combustion zone resulting in the steam flooding of oil.

2.       A substantial amount of carbon dioxide is released which causes with vaporization along with swelling of oil.

The first step in dry forward in-situ combustion is to ignite the oil. In some cases, autoignition occurs when air injection begins if the reservoir temperature is fairly high and the oil is reasonably reactive. This often occurs in California reservoirs. Ignition has been induced with:

After ignition, the combustion front is propagated by a continuous flow of air. Rather than an underground fire, the front is propagated as a glow similar to the hot zone of a burning cigarette or hot coals in a barbecue. As the front progresses into the reservoir, several zones exist between injector and producer as a result of:

  • Heat
  • Mass transport
  • Chemical reactions

Fig. 1[5] is an idealized representation of the various zones and the resulting temperature and fluid-saturation distributions. In the field, there are transitions between zones; however, the concepts illustrated provide insight on the combustion process.

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Zone definitions

Starting from the injector, seven zones have been defined.

A—The burned zone is the volume already burned. This zone is filled with air and may contain small amounts of residual unburned organic solids. Because it has been subjected to high temperatures, mineral alterations are possible. Because of the continuous airflow from the injector, the burned-zone temperature increases from injected-air temperature at the injector to combustion-front temperature at the combustion front.

B—The combustion front is the highest temperature zone. It is very thin, often no more than several inches thick. It is in this region that oxygen combines with the fuel and high-temperature oxidation occurs. The products of the burning reactions are water and carbon oxides. The fuel is often misnamed coke. In fact, it is not pure carbon but a hydrocarbon with H/C atomic ratios ranging from approximately 0.6 to 2.0. This fuel is formed in the thermal-cracking zone just ahead of the front and is the product of cracking and pyrolisis, which is deposited on the rock matrix. The amount of fuel burned is an important parameter because it determines how much air must be injected to burn a certain volume of reservoir.

C/D—The cracking/vaporization zone is downstream of the front. The crude is modified in this zone by the high temperature of the combustion process. The light ends vaporize and are transported downstream, where they condense and mix with the original crude. The heavy ends pyrolyze, resulting in:

  • CO2
  • CO
  • Hydrocarbon gases
  • Solid organic fuel deposited on the rock

E—The steam plateau. This is the zone in which some of the hydrocarbon vapours condense. Most of those condense further downstream as the steam condenses. The steam plateau temperature depends on the partial pressure of the water in the gas phase. Depending on the temperature, the original oil may undergo a mild thermal cracking, often named vis-breaking, that usually reduces oil viscosity.

F—A water bank exists at the leading edge of the steam plateau, where the temperature is less than steam saturation temperature. This water bank decreases in temperature and saturation downstream, with a resulting increase in oil saturation.

G—The oil bank. This zone contains most of the displaced oil, including most of the light ends that result from thermal cracking.

H—Beyond these affected areas is the undisturbed original reservoir. Gas saturation will increase slightly in this area because of the high mobility of combustion gases.


  • The reservoir fluid is highly viscous at the reservoir temperature, heating near the combustion front greatly reduces the viscosity, but the heated oil has to travel through the cold zone before reaching the production well which cools down and increases the viscosity.
  • Both the combustion and the injection are moving in the same direction.
  • Dry combustion has low sweep efficiency and high maintaining cost.
  • Temperature of the burning zone is high resulting in the generating large amounts of heat in the formation. But only small amount of heat is recovered due to the heat loss in the surrounding formation.

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Wet combustion

A large amount of heat is stored in the burned zone during dry forward in-situ combustion, (Fig. 3) because the low heat capacity of air cannot transfer that heat efficiently. Water injected with the air can capture and advance more heat stored in the burned zone. A technique where water is injected along with or alternatively with air into the reservoir. The injected water recovers the heat from the hot formation behind the combustion front and allows more efficient displacement of the oil. Temperature in the reservoir increases and decreases slowly as a result the rate of heat generation reduces, as the heat is transformed from the combustion zone into saturated steam and hot water zones. An optimum water-air ratio ratio results in more oil recovery.[6]

During the wet combustion process, injected water:

  • Absorbs the heat from the burned zone
  • Vaporizes
  • Moves through the burning front
  • Expands the steam plateau

Depending on the water/air ratio, wet combustion is classified as

  1. Incomplete when the water is converted into superheated steam and recovers only part of the heat from the burned zone
  2. Normal when all the heat from the burned zone is recovered and quenched
  3. Super wet when the front temperature declines as a result of the injected water.

When operated properly, water-assisted combustion reduces the amount of fuel needed, resulting in increased oil recovery and decreased air requirements to heat a given volume of reservoir. Up to a 25% improvement in process efficiency can be achieved.[7] Determination of the optimum water/air ratio is difficult because of reservoir heterogeneities and gravity override that can affect fluid movement and saturation distributions. Injecting too much water can result in an inefficient fire front, thus losing the benefits of the process.

Some authors recommend, as a best practice, injecting water at high rates to achieve "partially quenched combustion." This method has limited application. A high-temperature burn is preferred but is difficult to achieve with oils that are not highly reactive. Injecting large amounts of water can lower combustion temperatures, resulting in a greater fraction of oil burned and higher costs for oxygen. At the same time, these types of burns only partially oxidize the oil. This partial oxidation results in a much more viscous liquid, which in turn lowers the flow rate. So, in brief, if water injection is used, great care should be taken to assure that liquid water never reaches the high-temperature combustion front. A discussion of heat- and material-balance calculations that includes chemical reactions and the effect of injected air and water is presented later in some detail.


  • Wet combustion cannot avoid the liquid blocking problems.
  • The process is limited by the oil viscosity.
  • The combustion temperature is lower in wet combustion, hydrogen-carbon ratio of the utilized fuel increase with the decreases in the average temperature.

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Field experience

In-situ combustion has been used in the field since 1920. In the US, more than 230 projects have been implemented. Many of those were technically and economically successful. Failures resulted from:

  • Unfavourable reservoir and fluid characteristics
  • Poor design
  • Engineering or operational problems

Most of the failed projects were small pilot projects implemented in unfavourable reservoirs. Worldwide, combustion accounts for approximately 10% of the oil produced by thermal methods; 29 projects were active as of 1998.[1] Most of the projects outside of the US are large heavy oil projects, while the current trend in the US is to use in-situ combustion in deep, lighter-oil reservoirs in which waterflooding and steamflooding are not effective.

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Heavy oils

If we define heavy oil as gravity below 20° API, 19 projects using in-situ combustion were active in 1998. Some general comments are applicable:

  • Most of these projects last a long time; projects initiated in the 1960s are still active. Economics of successful projects are favorable even as compared to steamflooding and waterflooding.[8]
  • All the successful projects operate in the high-temperature mode.
  • Gravity override and channeling do occur. Gravity drainage of the hot oil is an important mechanism and should be maximized. Frequently, improved production of oil continues after the air injection has been terminated.
  • Line-drive projects, starting at the top of the reservoir and moving downward, exhibit superior performance compared to repeated pattern projects.
  • Most of the projects failed when air injection was attempted in different layers of the reservoir at the same time. Air injectivity is a critical parameter, and injectivity contrast between layers is usually too difficult to overcome.

Because a detailed description of all or even a few of the projects is outside the scope of this page, the reader can find additional information on several current projects in the following references:

  • Projects in Romania: Supplacu de Barcau is the world’s largest combustion project; it started in 1964 and is operated in a line-drive mode from the top downward. Videle and Balaria are other in-situ combustion projects.[9][10]
  • In India, Balol, which started as a pilot in 1990, was expanded to the whole field. Designed as a wet combustion project, the water injection rate had to be cut in half because of too much cooling. This project also was changed from patterns to updip line drive because of premature breakthrough in the producers.[11][12]
  • Projects in Russia, Kazakhstan, and Azerbaijan are not very well described in Western literature.[13]
  • The Albanian project of Kasnice is described in Marko et al.[14]
  • Batrum in Canada is a successful project using horizontal wells as producers. The Eyehill field is another project with horizontal wells.[12][15] Wabaska also uses the same concept of horizontal wells as producers.[16] Horizontal wells in in-situ combustion operations have been successfully used in Canada since 1993.

Cyclic applications such as pressure-up and blowdown, have been described.[16][17] This operational technique allows production from very low mobility oil fields or tar sands in which fracturing or cyclic steaming are needed before air injection. The Wabaska project is a cyclical combustion project with horizontal wells. This type of pressure-up, blowdown technique has also been successfully implemented at Wolf Lake.[17] Air was injected until the front arrived at the producers. When the front reached a given producer, this well was shut down, and cooling water was circulated. When all the producers were shut down, injection was stopped, and the producers reopened to blow down the reservoir. This process was repeated for several cycles. Operating combustion in this fashion allows production from fields in which injectivity is low because of a high crude viscosity at reservoir conditions.

US projects at Bellevue and Midway-Sunset have been described.[12] More details on the Midway-Sunset project can be found in Hoffmann.[18] Ramey et al.[19] describe the Belridge project as an economic success.

In-situ combustion in heavy oil reservoirs has been successful in both the dry and wet modes. Dry combustion early in the life of the project is the preferred method to form the desired high-temperature regime. When the process is well established, moderate amounts of water can be added to improve efficiency. Quenched, or super-wet, combustion seems to have limited success except when used at the end of a field operation to scavenge the heat remaining in the rock.

Another operating variation includes the use of enriched air or pure oxygen. Oxygen-enriched combustion presents technical and economic advantages for reservoirs with high pressure or very low injectivity. It has been demonstrated successfully in the field.[20][21] Commercial application of the oxygen technology has been limited because of oil price variations.

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Light oils

In-situ combustion is used in light-oil reservoirs for two different purposes:

  • To reduce the viscosity of unconventional light oils such as Demjen in Hungary[22] or Niemangu in China.[1] In these cases, thermal effects are important. In the case of Demjen, a catalyst had to be injected to promote combustion. Iron was used to increase the amount of fuel burned because the light oil by itself was not depositing enough fuel to sustain combustion. The oil is paraffinic and almost solid at reservoir temperature despite an API gravity of 32°.
  • To produce from light oil reservoirs in which waterflooding or other enhanced oil recovery methods are not attractive. Combustion is used to generate flue gases for reservoir pressure maintenance and production by gravity drainage. Thermal effects are only minor for this process. An interesting case is the West Hackberry double displacement process,[23] in which the gas cap is expanded for gravity drainage to recover residual oil after waterflood.

Combustion is successful in tight carbonate reservoirs located in the Dakotas, such as Medicine Pole Hill, Buffalo, west and south Buffalo,[24] and Horse Creek. In those cases, combustion allows exploitation of thin reservoirs with large well spacing.

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Screening guidelines

In-situ combustion is a complex process; it combines the effects of:

Because of its complexity, there is a misconception that combustion has a low probability of success. The truth is that combustion is an economically attractive, proven recovery process, capable of economically recovering a large fraction of the oil in place.

In-situ combustion can be applied to many different reservoirs. Some suggested screening guidelines are:

  • Nature of the formation: The rock type is not important provided that the matrix/oil system is reactive enough to sustain combustion. As in any drive process, high-permeability streaks are detrimental. Swelling clays may be a problem in the steam-plateau area.
  • Depth: The reservoir must be deep enough to ensure containment of the injected air in the reservoir. There is no depth limit, except that this may affect the injection pressure.
  • Pressure: This will affect the economics of the process but does not affect the technical aspects of combustion.
  • Temperature: Temperature will affect the propensity for autoignition but is otherwise not critical.
  • Reservoir thickness: Thickness must be greater than 4 m (15 ft) (Sarathi[1]) to avoid excessive heat losses to surrounding formations. Thick formations may present sweep-efficiency problems because of gravity override.
  • Permeability: This has to be sufficient to allow injection of air at the designed air flux. The air injectivity is especially important for heavy-oil reservoirs. Conditions are favorable when kh/μ is greater than 5md m/cp3.
  • Porosity and oil saturation: These must be large enough to allow economic oil recovery. The product, ФSo, should be more than approximately 0.08 for combustion to be economically successful.
  • Oil gravity: This parameter is not critical. In-situ viscosity has to be small enough to allow air injection and resulting oil production at the design rate.
  • Oil nature: In heavy oil projects, the oil should be readily oxidizable at reservoir and rock matrix conditions. This relationship must be determined by laboratory experiments. The same laboratory experiments can also determine the amount of air needed to burn a given reservoir volume. This is key to the economics of the process.

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Design considerations

Conditions favouring the use of in-situ combustion rather than steam include the following:

  1. High reservoir pressure at which steam is inefficient
  2. Potential for severe wellbore heat losses (i.e., depth, offshore, permafrost)
  3. Reservoir clay swelling in contact with fresh water
  4. Limited water supply
  5. Environmental regulations prohibiting steam generation

Like any other injection process, the design of in-situ combustion projects must consider injection-pressure limitations and reservoir flow resistance. These are especially important in heavy oil reservoirs in which combustion must occur in the high-temperature regime to be successful. The minimum air flux needed to maintain high temperatures at the front is estimated to be 0.125 ft/D (0.04 m/d).[25] Because the burn-zone growth is directly proportional to the injected air, the maximum air injection rate determines the minimum lifetime of the project. Ways to increase the air-injection rate are often needed, especially in heavy-oil reservoirs. They may include reduced well spacing, cyclic steaming of injectors and producers, and an increase in injection pressure. These factors will determine the compressor pressure and volume output.

There has been some controversy over whether in-situ combustion projects should be developed using patterns or line drives. Many early projects were started as pilots with a single injector. Usually, this practice ultimately resulted in a five-spot pattern. These pilots behaved contrary to plan, with the combustion front moving in only one direction because of permeability variations, gravity effects, well spacing differences, or a combination of these factors.

Attempts to correct the unbalanced flow included stimulating unresponsive wells and limiting withdrawal rates of wells that producing excessive volumes of combustion gas. Generally, these efforts did not have the desired effect.

In retrospect, this reservoir behavior makes sense. Once a combustion front is even slightly asymmetric, the higher temperature and, thus, higher mobility will cause greater flow in that direction. Thus, the flow will become more asymmetric, finally resulting in flow principally in only one direction.

Because it is often difficult to decide a priori which direction the major flow will take, operating plans should remain flexible until field performance indicates which injection scheme best uses the flow directions.

For the above reasons, many of the more successful in-situ combustion projects have been line-drive operations that start near the top of the reservoir and move downdip. In such an operation, the direction of the fire front is known. The operating engineers can then plan the completion and operating history in a rational way that will mirror the front movement and breakthrough history. This operating practice can be seen in most of the successful in-situ combustion field projects.

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In-situ combustion is applicable to a wide array of reservoirs. In fact, it is the only thermal method that can presently be applied to deep reservoirs, though deep downhole steam generation is being tested. It can be used at any stage of reservoir depletion; it can be used in special situations such as offshore or in Arctic regions. Because of the lack of heat losses at the surface and in the injection wells, it is the most thermally efficient thermal recovery method. The injectant (air) is readily available. Combustion allows wider well spacing than steam; economic results are comparable to those of steam injection.

Several aspects of operating in-situ combustion projects must be considered:

  1. The large compression ratio and associated costs required to inject air into the formation
  2. The planning and design requirements for a combustion project, which are more difficult than for steam injection
  3. Extensive laboratory work to assess fuel availability, air requirements, and burning characteristics of the crude that are required before designing in-situ combustion projects
  4. The high degree of technical sophistication and the careful monitoring needed to ensure proper operation of a project
  5. The limitation of numerical simulation and other techniques that makes predictions of recovery more difficult than most other enhanced oil recovery methods.

Combustion temperature ranges between 350˚C - 500˚C depending on the rate of injection. Oil recovery increases primarily due to two main reasons: one the steam zone is created causing steam flooding of oil, and two small amounts of CO2 is generated which increases the vaporization and the swelling of oil. Oil zone thickness plays an important role, as the thermal energy can be bypassed by the air channellings. Using these processes extra oil can be produced, whereas with only waterflooding it cannot. The fuel consumed during the combustion process is small amount when compared with the produced fuel. In-situ combustion process can recover the oil in high volume when the reservoir depth is large enough space to inject the air/water in the reservoir. Using mixtures of oxygen and CO2 injection in place of air improves the rate of recovery, because CO2 is easily miscible at low pressure, which allows swelling of oil and reduction in viscosity of oil. This process is suitable for oil gravity between 10˚ - 40˚API.

Considerable improvements in the application of in-situ combustion have been made since the early projects. New developments, such as application to light oil reservoirs, and the use of horizontal wells are reviving interest in in-situ combustion. This process deserves consideration for many reservoirs, including those in hostile environments or those not amenable to other recovery methods.

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  1. 1.0 1.1 1.2 1.3 1.4 Sarathi, P. 1999. In-Situ Combustion Handbook Principles And Practices. Report DOE/PC/91008-0374, OSTI ID 3175 (January).
  2. 2.0 2.1 Prats, M. 1982. Thermal Recovery, Vol. 7. Richardson, Texas: Monograph Series, SPE.
  3. 3.0 3.1 Burger, J., Sourieau, P., and Combarnous, M. 1989. Thermal Methods Of Oil Recovery. Paris, France: Editions Technip.
  4. Tabasinejad, F., Karrat, R., Vossoughi, S., & Kansas, U. (2006). Feasibility Study of In-Situ Combustion in Naturally Fractured Heavy Oil Reservoirs. Society of Petroleum Engineers, (SPE 103969).
  5. 5.0 5.1 Wu, C.H. and Fulton, P.F. 1971. Experimental Simulation of the Zones Preceding the Combustion Front of an In-Situ Combustion Process. SPE Journal 11 (1): 38-46. SPE-2816-PA.
  6. Partha,S,S. (1999). In-situ combustion handbook – principles and practices. Tulsa, OK: BDM Petroleum Technologies.
  7. Bousaid, S. 1989. Multiple-Quenched Fireflood Process Boosts Efficiency. J Pet Technol 41 (11): 1202-1209. SPE-16739-PA.
  8. Ramage, W.E., Castanier, L.M., and Ramey Jr., H.J. 1987. Economic Evaluation of Thermal Recovery Projects. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 27-30 September 1987. SPE-16852-MS.
  9. Machedon, V. 1993. Suplacu de Barcau field: 28 years of in situ combustion. Proc., 7th European Symposium on Enhanced Oil Recovery, Moscow.
  10. Machedon, V. 1995. Romania: 30 years of experience in in-situ combustion. Proc., NIPER/DOE Symposium on In-situ Combustion, Tulsa (21–22 April 1994); US DOE Report NIPER/BDM-0086.
  11. Roychaudurhi, S. et al. 1995. Experience with in-situ combustion pilot in presence of edge water. Proc., 6th UNITAR Conference on Heavy Crudes and Tar Sands, Houston, 12–17 February.
  12. 12.0 12.1 12.2 Moritis, G. 1998. EOR Oil Production Up Slightly. Oil & Gas J. (20 April): 49.
  13. Mamedov, Y.G. and Bocserman, A.A. 1995. Development of heavy oils and bitumen in the former Soviet Union and eastern and central Europe. Proc., 6th UNITAR Conference on Heavy Crudes and Tar Sands, Houston, 12–17 February.
  14. Marko, D. 1995. Oil production history in Albanian fields and their perspective. Proc., 6th UNITAR Conference on Heavy Crudes and Tar Sands, Houston, 12–17 February.
  15. Ames, B.G., Gramms, R.E., and Pebdani, F.N. 1994. Improved sweep efficiency through application of horizontal well technology in a mature combustion EOR. Proc., NIPER/DOE Symposium on In-Situ Combustion, Tulsa, 21–22 April; U.S. DOE Report NIPER/BDM-0086 (January).
  16. 16.0 16.1 Marjerrison, D.M. and Fassihi, M.R. 1994. Performance of Morgan Pressure Cycling In-Situ Combustion. Presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 17–20 April. SPE-27793-MS.
  17. 17.0 17.1 Hallam, R.J. and Donnelly, J.K. 1993. Pressure-Up Blowdown Combustion: A Channeled Reservoir Recovery Process. SPE Advanced Technology Series 1 (1): 153-158. SPE-18071-PA.
  18. Hoffmann, S.J. 1998. Successful Application of In Situ Combustion to a Dipping Heavy Oil Reservoir Midway Sunset Field. Paper 39639 presented at the 1998 SPE/DOE Symposium, Tulsa.
  19. Ramey, H.J.J., Stamp, V.W., Pebdani, F.N. et al. 1992. Case History of South Belridge, California, In-Situ Combustion Oil Recovery. Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 22–24 April. SPE-24200-MS.
  20. Hvizdos, L.J., Howard, J.V., and Roberts, G.W. 1983. Enhanced Oil Recovery Through Oxygen-Enriched In-Situ Combustion: Test Results From the Forest Hill Field in Texas. J Pet Technol 35 (6): 1061-1070. SPE-11218-PA.
  21. Moore, R.G., Bennion, D.W., Belgrave, J.D.M. et al. 1990. New Insights Into Enriched-Air In-Situ Combustion. J Pet Technol 42 (7): 916-923. SPE-16740-PA.
  22. Racz, D. et al. 1985. Development of a thermocatalytic in situ combustion process in Hungary. Proc., 1985 European Meeting on Improved Oil Recovery, Rome, April.
  23. Gillham, T.H., Cerveny, B.W., Turek, E.A. et al. 1997. Keys to Increasing Production Via Air Injection in Gulf Coast Light Oil Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October 1997. SPE-38848-MS.
  24. Miller, R.J. 1995. Koch’s experience with deep in-situ combustion in Williston basin. Proc., NIPER/DOE Symposium on In-Situ Combustion, Tulsa, 21–22 April; U.S. DOE Report NIPER/BDM-0086 (January).
  25. Nelson, T.W. and Mc Neil, J.S. 1961. How to engineer an in-situ combustion project. Producer Monthly (May; Oil & Gas J. (5 June).

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Noteworthy papers in OnePetro

Chu, C. 1982. State-of-the-Art Review of Fireflood Field Projects (includes associated papers 10901 and 10918 ). J Pet Technol 34 (1): 19-36. SPE-9772-PA.

Counihan, T.M. 1977. A Successful In-Situ Combustion Pilot in the Midway-Sunset Field, California. Presented at the SPE California Regional Meeting, Bakersfield, California, 13-15 April 1977. SPE-6525-MS.

Dietz, D.N. 1970. Wet Underground Combustion, State of the Art. J Pet Technol 22 (5): 605-617.

Ejiogu, G.J., Bennion, D.W., Moore, R.G. et al. 1979. Wet Combustion-A Tertiary Recovery Process For the Pembina Cardium Reservoir. J Can Pet Technol 18 (3). PETSOC-79-03-05.

Farouq Ali, S.M. 1972. A Current Appraisal of In-Situ Combustion Field Tests. J Pet Technol 24 (4): 477-486. SPE-3350-PA.

Cadelle, C.P., Burger, J.G., Bardon, C.P. et al. 1981. Heavy-Oil Recovery by In-Situ Combustion - Two Field Cases in Rumania. J Pet Technol 33 (11): 2057-2066. SPE-8905-PA.

Gates, C.F., Jung, K.D., and Surface, R.A. 1978. In-Situ Combustion in the Tulare Formation, South Belridge Field, Kern County, California. J Pet Technol 30 (5): 799-806. SPE-6554-PA.

Gates, C.F. and Sklar, I. 1971. Combustion as a Primary Recovery Process-Midway Sunset Field. J Pet Technol 23 (8): 981-986. SPE-3054-PA.

Greaves, M., Dong, L. L., & Rigby, S. 2012. Validation of Toe-to-Heel Air-Injection Bitumen Recovery Using 3D Combustion-Cell Results. Society of Petroleum Engineers.

Gutiérrez, D., Moore, R. G., Ursenbach, M. G., & Mehta, S. A. 2012. The ABCs of In-Situ-Combustion Simulations: From Laboratory Experiments to Field Scale. Society of Petroleum Engineers.

Joseph, C. and Pusch, W.H. 1980. A Field Comparison of Wet and Dry Combustion. J Pet Technol 32 (9): 1523-1528. SPE-7992-PA.

Kerr, R. K., & Jonasson, H. P. 2013. SAGDOX - Steam Assisted Gravity Drainage With the Addition of Oxygen Injection. Society of Petroleum Engineers.

Paitakhti Oskouei, S. J., Maini, B. B., Moore, R. G., & Mehta, S. A. 2013. Experimental Evaluation of SAGD/ISC Hybrid Recovery Method. Society of Petroleum Engineers.

Showalter, W.E. and Maclean, A.M. 1974. Fireflood at Brea-Olinda Field, Orange County, California. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 22-24 April 1974. SPE-4763-MS.

Showalter, W.E. 1963. Combustion-Drive Tests. SPE J. 3 (1): 53-58.

Terwilliger, P.L., Clay, R.R., Wilson Jr., L.A. et al. 1975. Fireflood of the P2-3 Sand Reservoir in The Miga Field of Eastern Venezuela. J Pet Technol 27 (1): 9-14. SPE-4765-PA.

Widmyer, R.H., Howard, C.E., Fontaine, M.F. et al. 1977. The Charco Redondo Thermal Recovery Pilot. J Pet Technol 29 (12): 1522-1532. SPE-5822-PA.

Williams, R.L., Jones, J.A., and Counihan, T.M. 1987. Expansion of a Successful In-Situ Combustion Pilot in the Midway Sunset Field. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 27-30 September 1987. SPE-16873-MS.

Zhu, Z., Bazargan, M., Lapene, A., Gerritsen, M. G., Castanier, L. M., & Kovscek, A. R. 2011. Upscaling for Field-scale In-situ Combustion Simulation. Society of Petroleum Engineers.

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External links

Use this section to provide links to relevant material on websites other than PetroWiki and OnePetro

See also

Laboratory studies of in-situ combustion

Predicting behavior of in-situ combustion

Predicting performance of in-situ combustion

Operating practices for in-situ combustion

Thermal recovery by steam injection

Electromagnetic heating of oil

Steam assisted gravity drainage


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