You must log in to edit PetroWiki. Help with editing

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information

PEH:In-Situ Combustion

Jump to navigation Jump to search

Publication Information


Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume V – Reservoir Engineering and Petrophysics

Edward D. Holstein, Editor

Chapter 16 – In-Situ Combustion

William E. Brigham and Louis Castanier, Stanford U.

Pgs. 1367-1398

ISBN 978-1-55563-120-8
Get permission for reuse

In-situ combustion (ISC) is the oldest thermal-recovery technique. It has been used for more than nine decades with many economically successful projects. Nevertheless, it is regarded as a high-risk process by many primarily because of the many failures of early field tests. Most of those failures came from the application of a good process (ISC) to the wrong reservoirs or the poorest prospects. An objective of this chapter is to clarify the potential of ISC as an economically viable oil-recovery technique for a variety of reservoirs. This chapter is a summary containing a description of ISC, a discussion of laboratory screening techniques, an illustration of how to apply laboratory results to field design, a review of performance-prediction methods, a discussion of operational practices and problems, and an analysis of field results. For a more complete review, the work of Sarathi,[1] Prats,[2] and Burger et al.[3] should be consulted.

Process Description

ISC 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 gasdrive (from the combustion gases), steam, and waterdrive. 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 forward (when the combustion front advances in the same direction as the air flow) or reverse (when the front moves against the air flow).

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.

First, 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 ISC project.

Second, 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.

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

Forward Combustion

Because only forward combustion is practiced in the field, we will only consider this case. Forward combustion can be further characterized as "dry" when only air or enriched air is injected or "wet" when air and water are coinjected.

Dry Combustion.The first step in dry forward ISC 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 downhole gas burners, electrical heaters, and/or injection of pyrophoric agents or steam injection; it will be discussed in more detail later.

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, and chemical reactions. Fig. 16.1[4] 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.

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 pyrolize, resulting in CO2, CO, hydrocarbon gases, and solid organic fuel deposited on the rock.
E—The steam plateau. This is the zone in which some of the hydrocarbon vapors 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 visbreaking, 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.

Wet Combustion. A large amount of heat is stored in the burned zone during dry forward ISC, (Fig. 16.1) 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.

During the wet combustion process, injected water absorbs the heat from the burned zone, vaporizes, moves through the burning front, and expands the steam plateau. As a result, the steam plateau is extended. This results in faster heat movement and oil displacement.

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 or (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.[5] 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.

Laboratory Studies

ISC processes are largely a function of oil composition and rock mineralogy. The extent and nature of the chemical reactions between crude oil and injected air, as well as the heat generated, depend on the oil-matrix system. Laboratory studies, using crude and matrix from a prospective ISC project, should be performed before designing any field operation.

The Reactions

The chemical reactions associated with ISC are complex and numerous. They occur over a broad temperature range. Most researchers group them into three classes in ascending temperature ranges:

  • Low-temperature oxidation (LTO)—heterogeneous gas/liquid reactions producing partially oxygenated compounds and few carbon oxides.
  • Medium-temperature reactions—cracking and pyrolisis of hydrocarbons to form fuel.
  • High-temperature oxidation (HTO)—heterogeneous H/C bond breaking reactions in which the fuel reacts with oxygen to form water and carbon oxides.

A more recent and more accurate kinetics model has been developed.[6] Only two reactions are used, but in addition, the geometry of the reacting residual fuel in the pore spaces is taken into account, as indicated in Fig. 16.2. The crude-oil oxidation consists of two stages: LTO forming an oxygenated hydrocarbon fuel, and high-temperature combustion of this fuel. A detailed description of the different reaction regimes is outside the scope of this Handbook; some practical comments on the role of LTO, however, are appropriate at this stage.

LTO can be described as oxygen addition to the crude oil. LTO yields water and oxygenated hydrocarbons such as ketones, alcohols, and peroxides. A good description of LTO can be found in Burger.[7] LTO generally increases original oil viscosity, boiling range, and density. LTO increases the amount of fuel and is promoted by low air flux in the oxidation zone. Poor crude oxidation characteristics can also play a role. In heavy-oil reservoirs (API gravity < 20°), LTO tends to be more pronounced when oxygen (rather than air) is injected in the reservoir.[8]

A U. of Calgary research team has shown that, for heavy oils, LTO reactions must be minimized. Fig. 16.3 shows the oxygen uptake as the temperature of a typical heavy oil is raised linearly with time. Notice the negative temperature-gradient region, that is, the region in which oxygen-rate uptake decreases with temperature increase. If the temperature of the ISC process stays at or below the negative temperature-gradient region, the oil displacement efficiency will be very low. This is because LTO increases the oil viscosity and fuel content. The injected-air flux in a heavy-oil project should be maintained at a value well above the value needed to maintain the reactions in the high-temperature oxidation regime. LTO generally has almost no effect on light oils in terms of mobility or recovery despite the fact that light oils are more susceptible to LTO than heavy oils.

Fuel deposition determines the feasibility and economic success of a combustion project. It occurs at intermediate temperatures after the LTO reactions. Numerous studies have been conducted in an attempt to understand fuel formation and deposition at intermediate temperatures. The oil type and chemical structure determine the rate and extent of the different reactions. Catalytic effects from the matrix and/or injected solutions of metals may affect the type and amount of fuel formed. Again, all laboratory experiments must include not only the crude to be tested but also representative core material from the reservoir of interest.


Kinetics of combustion reactions can be defined by how fast the chemical reactions occur and how much of the oil is affected. It is important to study kinetics for several reasons:

  • Characterization of oil reactivity.
  • Determination of ignition conditions.
  • Insight on the nature of the fuel and its combustion characteristics.
  • Use of kinetic parameters as input for possible numerical simulation of the process.

Because crude oils contain hundreds of different compounds, it is impossible to accurately represent all the reactions occurring during ISC. Even if it were possible to detail all the reactions, the use of such information in numerical models would be impossible because of cost and computer limitations. Consequently, we will concentrate on useful simple models describing ISC reaction kinetics that have been published in the literature. Most studies use the Arrhenius expressions defined as follows. The model assumes a functional dependency on fuel concentration and oxygen partial pressure. It is given by


where RC = reaction rate of the crude, kg/m3s; Cf = concentration of fuel, kg/m3; and RTENOTITLE = oxygen partial pressure, Pa.

The exponent constants, a and b, are the orders of the reactions with respect to oxygen partial pressure (a) and fuel concentration (b). Data show that a ranges between 0.5 and 1.0, while b is close to 1.0. The reaction rate, K, is the Arrhenius constant, expressed as a function of temperature as follows:


where A = Arrhenius rate constant; E = activation energy, kJ/mol; T = absolute temperature, °K; and R = 0.00831 universal gas constant, kJ/mol °K.

When using literature values, be careful because the parameters in Eqs. 16.1 and 16.2 vary depending on the system of units used.

A variety of experimental techniques can be used to determine the kinetics of ISC reactions. Among those are differential thermal analysis, thermogravimetric analysis, accelerating rate calorimetry, and effluent analysis. The reference list contains several descriptions of various methods and results.

The effluent analysis method, also called the ramped temperature method in Canada, is quantitative and consists of heating a sample of oil and rock while flowing oxygen (for oxidation) or nitrogen (for pyrolisis) through the sample. The kinetic parameters can be calculated from effluent gas evolution with temperature and chemical analysis of post-test cores. Details of the analysis techniques can be found in multiple sources.[3][6][9]

Combustion-Tube Studies

Although the kinetic studies can provide useful insight on ISC reactions, combustion-tube experiments are mandatory to determine the parameters needed to design and implement field projects. These data are used to make predictions of field test performance. As Sarathi[1] points out, "Combustion-tube studies are the necessary first step in the design of an ISC project."

Combustion tubes aim at representing a small volume of the reservoir. They are usually packed with native reservoir cores or representative samples of matrix material and oil, placed in vertical position to minimize gravity effects and heated to reservoir temperature. Ignition is usually started at the top by electrical heaters, and the combustion front is propagated downward. This allows propagation of a combustion front and the associated chemical reactions at conditions close to those in a reservoir.

Temperature profiles, pressures, gas and liquid injection and production rates, and composition histories at the inlet and outlet are recorded. ISC tube runs are unscaled, and direct correlation of combustion-tube results to the field is not possible. However, as long as the runs are performed with reservoir rock and fluids at reservoir conditions, the reactions of fuel deposition and combustion will be similar in both tube and reservoir.

Tube runs will not provide information on ISC sweep efficiency. They adequately model the chemistry of the process, but not the flow behavior in the reservoir, and only partially model the heat-transfer processes. Flow behavior in the reservoir is affected by gravity override, well spacing, and geometry and reservoir heterogeneities, and tube runs cannot reproduce these phenomena. Heat transfer from the tube to the surroundings can be much higher than reservoir heat losses.

Two different schools of thought exist on this heat-transfer problem. Many experimenters use strip heaters around the tube to lessen the temperature gradient between the tube and the surroundings. This practice can, however, lead to overestimation of water/oil ratios in wet combustion if the strip heaters provide too much energy to the system, as they often do. Information on front cooling by injected water may also be masked by the heaters. As a result, the extent of the steam plateau may not be correct. Most of these types of experiments are bulky and time consuming and require extensive instrumentation.

The other solution is to increase the air flux and minimize heat losses by insulation alone. This may slightly overestimate air requirements and fuel content but is much simpler and easier to operate. As a result, it is widely used. Descriptions of various setups for combustion-tube studies have been provided.[5][6][10][11][12]

The information that can be acquired from tube runs includes:

  • Fuel burned.
  • Air required to burn a unit volume of reservoir.
  • Atomic H/C ratio of burned fuel.
  • Excess air and oxygen use.
  • Air/fuel ratio.
  • Oil recovery from the swept zone.
  • Optimization of water/air ratio in wet combustion.
  • Composition of produced fluids.
  • Front temperature and stability.

This last piece of information is quite important in heavy oils to determine if the process is operating properly in the desired high-temperature regime. If high temperature cannot be achieved in ideal laboratory conditions, it is likely that field results would be worse.

Data Analysis.The following is a simple analysis of data from tube runs. It assumes that the combustion occurs at high temperature where the fuel exclusively combines with oxygen to produce water and carbon oxides. The stoichiometric equation[13] is then


where n = hydrogen/carbon atomic ratio of fuel and m = CO2/CO concentration ratio produced. The other symbols indicate the various components in the chemical-balance equation.

This equation is only an approximation of the process. It neglects LTO reactions, oxygen/mineral reactions, and water/organic fuel reactions. Alternate analysis when some of these reactions are important is detailed in Sarathi[1] based on work from Moore and Mehta.[10] Assuming Eq. 16.3 to be valid, the apparent H/C ratio, n, can be estimated from the concentration of exhaust gases and the injected oxygen concentration.[13]


where (O2)prod = oxygen concentration produced.

It is prudent to normalize the concentrations by making a balance on the nitrogen, which in these conditions can be considered inert. The basic chemical equation is then


where R is the molar ratio of nitrogen to oxygen in the feed gas, and a, b, d, and f are stoichiometric coefficients similar to those in Eq. 16.3.

The range of the ratio, n, for high-temperature reactions should be from 0.5 to 2. Calculation of an unusually high value of n indicates that LTO is important. In the very early stages of field projects, large n values are often observed because of the solubility of the combustion gases (particularly CO2) in the oil.

Once n and m are known, the amount of air required to burn one unit weight of fuel is found from Eq. 16.3. The heat generated by burning a unit weight of fuel can be calculated by simple addition of the heat generated by each reaction, as described in the stoichiometric equation (Eq. 16.3). The calculation of heat produced must take into account the production of carbon monoxide. The following formula[13] can estimate heating values of fuels as a function of n and m.


where Hc = heating value, Btu/lbm fuel. To convert to J/kg, multiply by 2,326.

The air required to burn a given volume of reservoir is, of course, a very important design parameter and one of the keys to the economics of the combustion process. This is calculated directly from the experimental data by dividing the amount of oxygen consumed by the volume swept during the tube run. The mass of fuel burned in a unit volume of reservoir can be calculated from the oxygen consumed by a unit volume and by applying Eq. 16.3. All other relevant parameters can be estimated.[13][14] It is prudent to perform multiple laboratory tube runs before field implementation.

Combining Material- and Heat-Balance Calculations

Many useful and reasonably accurate calculations can be made on ISC to predict the behavior of a proposed project. These ideas will be explained in the following diagrams and example calculations. They start with a very simple heat balance and are then extended to more closely represent what happens in the reservoir.

First Assumptions

Start by assuming that no combustion data are available to get an initial idea of the feasibility of a project. This preliminary work gives the engineer a sound basis to decide whether further work has economic promise.

Assume a sandstone formation with a porosity of 22%, a temperature of 100°F, a 24°API oil at a saturation of 65%, and an injection pressure of 300 psia. Also assume the CO2/CO atomic ratio m to be


This is a reasonable ratio to assume, based on both laboratory and field experience.

Because there are no tube run data, generalized correlation curves[13] (Figs. 16.4 and 16.5) will be used to calculate expected results. From Fig. 16.4, the fuel availability, W, for 24°API crude is


The apparent H/C atomic ratio (n) of the fuel is also needed. This is a function of the combustion-front temperature,[13] as shown in Fig. 16.5. Selected data from the graph are listed in Table 16.1. These data for 21.8°API crude are close enough to 24°API crude for initial estimates.

Calculate Initial Heat Balances and Temperatures

Start by assuming that all heat generated is used to heat the rock formation through which the combustion front has moved. This assumption is not accurate, but it simplifies the understanding of the mathematics and concepts involved in heat-balance calculations. A sketch of the temperature profile generated is shown in Fig. 16.6. Corrections to this heat balance calculation will be discussed later.

Assuming 1.0 ft3 of rock formation burned and a front temperature of 1,000°F, from Eq. 16.8 and Table 16.1,


Quartz weighs approximately 164 lbm/ft3. The amount of fuel for a cubic foot of formation equals


Using the heat of combustion, Eq. 16.6, with the appropriate parameters, becomes


Thus, the total heat generated is


Next, calculate the temperature rise of the formation behind the front to see if it matches the temperature assumed by performing a heat balance behind the front. Because, for practical purposes, the only fluid in the formation behind the front is air (which has a very small volumetric heat capacity), we only need to calculate a heat balance on the sandstone itself. A good equation for average sandstone heat capacity is[13]



where T1 = initial reservoir temperature, °F and T2 = final reservoir temperature, °F.

From a heat-balance calculation, the reservoir sand temperature is as follows:


The result from Eq. 16.14 does not agree with the assumed temperature of 1,000°F. Calculations with other assumed temperatures result in the calculated temperature values shown in Table 16.2.

The tabular data are graphed as circles in Fig. 16.7. The two temperatures match at 801°F. This is the calculated combustion-front temperature if all the heat generated is used to heat the formation behind the combustion front.

Correction for Water of Combustion

These results do not include all the processes occurring in the reservoir. First, the water formed by combustion will condense beyond the combustion front, absorb some heat of combustion, and reduce the heat of the formation behind the combustion front. This effect can be calculated as follows.

From Eq. 16.9, 0.0317 lbm of H2 are burned per 100 lbm of rock at 1,000°F. Assuming that a pound of steam will release 1,000 Btu when cooling from combustion temperature and condensing (this number is only approximately correct but is adequate for estimation purposes), the amount of heat carried forward by the steam is calculated with concepts similar to Eqs. 16.10 and 16.12:


In this equation, 18/2 is the ratio of molecular weight of water and hydrogen. The heat given up by the steam is 1,000 Btu/lbm, and the other numbers are similar to those in Eq. 16.10. Thus, the calculated temperature is lower than it was in Eq. 16.14, as shown below:


Other temperatures were calculated in a similar way, and the results, graphed as triangles in Fig. 16.7, show a corrected combustion temperature of 788°F. At this temperature, the H/C ratio is 0.85, as indicated in Fig. 16.8.

Calculating the Volume and Temperature of the Steam Plateau

No calculations on the steam plateau were necessary in the above calculations. The steam-plateau temperature and volume directly affect the volume of oil moved as a result of the combustion process. To calculate these terms, use the H/C ratio of 0.85 and calculate the partial pressure of the water as follows.

The fuel composition is CH 0.85 . From Eq. 16.3, the moles of oxygen used per mole of fuel are


Combustion products are calculated in a similar way:





The operating pressure is 300 psia. The partial pressure of H2O in the combustion gas is


From steam tables, the saturation temperature for 21.6 psia is 232°F. This is the temperature of the steam plateau.

The volume of the steam plateau is a function of the amount of H2O formed. Knowing that there are 0.95 lbm C/100 lbm rock burned, and knowing from Fig. 16.8 that the H/C ratio is 0.85, an equation similar to Eq. 16.10 yields the amount of water formed per cubic foot of rock burned.


Thus, the total heat carried forward by the water formed is


Using Eq. 16.13a, the heat capacity of the formation is


The amount of heat required to raise the temperature of a cubic foot of sand from 100 to 305°F, from a heat balance, is


Thus, the volume of rock heated by condensing steam is Eq. 16.23 divided by Eq. 16.24:


A sketch of the resulting temperature profile is shown in Fig. 16.9.

Calculating the Effects of Injected Air and Water

Further corrections are needed to increase the accuracy of the temperature profile in Fig. 16.9. Injected air will partially cool the burned zone, raise the temperature as it approaches the combustion front, and carry heat forward. This will have little effect on the combustion kinetics or the amount of heat generated by combustion, so, in essence, this amount of energy is merely carried forward to extend the size of the steam plateau.

A sketch of this idea is shown in Fig. 16.10. In this sketch, the area marked "1" is the temperature profile behind the burning front; Area 2 is the steam plateau, which is now larger than calculated before because of the heat carried forward by the combustion gases.

This temperature profile can be approximated as indicated in Fig. 16.11, where the profiles of the burned zone and steam plateau are treated as square waves that have been adjusted so that the total heat in Areas 1 and 2 is the same as in Fig. 16.10.

There are several reasons for using this square-wave concept. One is that it makes it easier to calculate heat losses to be expected from either a laboratory or field combustion operation using superposition calculations similar to those discussed by Ramey as seen in Prats.[2] The reference also indicate that the heat losses calculated with Fig. 16.11 are quite adequate.

When wet combustion is used, the temperature behind the front tends to change abruptly, as shown in Fig. 16.11. As a result, heat and material balances of the sort discussed next can be used to calculate the movement of the resulting cooling front, burn front, and steam plateau.

The amount of air injected per cubic foot of rock burned and the heat capacity of air are needed to calculate this heat-transfer process for dry combustion. The volume of combustion gas should also theoretically be calculated, but normally this isn’t necessary because its volume is nearly identical to the air volume. Further, its heat capacity is nearly the same—remember that most of the combustion gas is nitrogen (assuming that air is injected).

The moles of air injected are calculated by adding the O2 from Eq. 16.17 to the N2 from Eq. 16.21:


The heat capacity for air is 7.00 Btu/lbm mol-°F. With previously determined factors of 0.95 lbm of carbon burned for 100 lbm rock, 164(1 – 0.22) pounds of rock per cubic foot of rock, 12 lbm of carbon per mole, a combustion-zone temperature of 788°F (Fig. 16.7, and the results of Eq. 16.26, we obtain the amount of heat carried forward by the injected air as follows.


This heat extracted behind the burned zone is deposited into the steam plateau. The resulting size of the steam plateau can be calculated in a way similar to Eq. 16.25 by adding the heat carried by the combustion gas to that carried by the water as follows:


This calculation shows that the condensing steam front is far enough ahead of the combustion front to displace oil efficiently, and it is unnecessary to have the combustion front cover the entire reservoir to obtain good recovery. Recovery can be estimated by knowing the amount of fuel burned, by estimating the residual oil saturation in the steam plateau, and by estimating the volumetric sweep efficiency of the process.

Heat Losses

An estimate of heat losses using the superposition concepts seen in Prats,[2] based on Ramey’s work, will make the calculations just presented more accurate. These estimates are particularly important if a laboratory heat balance indicates significant heat losses. The temperature profiles just calculated assuming no heat losses can be used to make a first estimate of heat losses and a recalculated steam-plateau size. This is a reasonable way to handle the heat balance. Because all heat transferred was assumed to be in the steam plateau, any reduction in that transferred heat because of losses will reduce the amount of heat in the plateau.

Because the size of the steam zone and the size of the calculated heat losses are interdependent, iterative calculations are necessary until the assumed and calculated heat balances match. This will usually require only two to three iterations to achieve this match.

Data used in the previous calculations were based on generalized predictions of combustion behavior (i.e., the amount of fuel per cubic feet of formation) and the H/C ratio of the fuel. If combustion tube runs are made in the laboratory, those parameters will be known and should be used in the calculations. In addition, accurate temperature and saturation profiles vs. time will allow reasonably accurate heat-balance calculations to determine the heat losses from the experiment. As an alternative, reasonable assumptions about the heat losses can be used to check the heat-balance calculations and indicate if there is significant experimental error.

Computer assisted tomography (CAT) scanner measurements produce the most accurate saturation histories. Accurate measurements of temperature profile and accurate oil, water, and gas production data also make it possible to estimate reasonable saturation histories. These are the major sources of error in the overall heat-balance calculations, but they are fairly small compared to the amount of heat stored in the hot matrix.

Design Considerations

Conditions favoring the use of ISC 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, and (5) environmental regulations prohibiting steam generation.

Like any other injection process, the design of ISC 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).[14] 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 ISC 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 ISC 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 ISC field projects to be discussed later.

Performance Prediction

Predicting the production response to ISC has been the topic of various studies. Complete numerical simulation of ISC is difficult because of the complex reactions and the thin burning front that requires small gridblocks for representation. Simulators range from tank models to complex 3D simulators. In addition to simulation, empirical models, hybrid models, and correlation methods have been developed. A discussion of some of these methods follows.

The easiest method is essentially a tank balance,[14] adapted by Prats.[2] The oil and water produced are given by




where Soi = initial oil saturation, fraction; Sf = oil saturation burned, fraction; Vb = volume burned, m3 ; Np = oil produced, m3 ; Wp = water produced, m3; Ф = porosity, fraction; Vp = volume of the pattern, m3; and Swf = water saturation resulting from the combustion process, fraction.

If the volumes are in acre-ft and the production terms are in bbl, a multiplication factor of 7,758 must be used. The estimate of 40% of the oil produced coming from outside the burned volume is an empirical value based on experience. This is the 0.4 term in Eq. 16.29.

Fig. 16.12, presented by Gates and Ramey,[15] combines laboratory results and field observations from the Belridge ISC projects. It shows the effect of initial gas saturation on the oil-recovery history. Oil production rates and instantaneous air/oil ratios can be estimated from the slopes of the curves. At late times, the above two techniques give similar results.

Satman and Brigham[16] used data from dry combustion field tests to obtain two empirical correlations. Those are presented in Figs. 16.13 and 16.14. The terms in the ordinates are cumulative incremental oil produced (CIOP), original oil in place (OOIP), fuel burned (FB), and oil in place (OIP) at the start of the project.

In addition to original oil saturation So, thickness h, oil viscosity μo, and porosity Ф, the abscissa includes cumulative air injected (CAI), and OIP at the start of the project, and fraction oxygen use. The second correlation, Fig. 16.14, is the most accurate except for oils with less than 10 cp original viscosity, where the first correlation must be used. These correlations were generated from pilot floods; thus, they would not be expected to be accurate for pattern flooding. However, the narrative in the previous section points out that pattern flooding is generally not the best way to operate an ISC project, and these correlations are expected to be reasonably accurate for line-drive projects.

Operating Practices

In addition to the standard field equipment for oil production, ISC requires particular attention to air compression, ignition, well design, completion, and production practices.


Air-compression systems are critical to the success of any ISC field project. Past failures often can be traced to poor compressor design, faulty maintenance, or operating mistakes. A detailed discussion of compressors and sizing considerations appears in the Facilities and Construction Engineering volume of this Handbook. Other discussions are available in Sarathi.[1]

The factors to be considered when selecting compressors include peak air requirements, injection pressure, capital cost, power requirements, operation and maintenance costs, and other relevant technical and economic parameters specific to the field considered. Compressor terminology varies among manufacturers. It is best to obtain a complete description including compressor, driver, interstage cooling system, and all ancillary equipment, including control and safety systems from each vendor being consulted.

Air compression causes high temperatures because of the large heat capacity (cp/cv ratio). Compressor design must consider these high temperatures to ensure continuous, sustained operations free from the corrosive effects of air and the explosion hazards of some lubricating fluids. Mineral oils are not recommended. Synthetic lubricants withstand the higher temperatures and offer lower volatility and flammability than conventional lubricants.


Ignition and maintenance of high combustion temperatures, especially in heavy-oil projects, are the most critical factors of an ISC project. Shallcross[17] presented a complete review of ignition methods. The following is a summary of this study.

Ignition can occur spontaneously if the oil is reactive, the reservoir temperature is high enough, and the reservoir is reasonably thick. Various models have been proposed to determine the time for spontaneous ignition.[18][19]

When spontaneous ignition does not occur or is not desired (i.e., in heavy oil reservoirs, where it is important to maintain high combustion temperatures), the most appropriate ignition method depends on the reservoir and the equipment available on site.

Downhole gas-fired burners allow good control of the temperature of injected gases and may be operated at a greater depth than other methods. The disadvantages include the need to run multiple tubing strings in the injection wells. Some particulates such as soot may be carried into the formation if the gas does not burn cleanly.

Catalytic heaters run at lower temperatures but are sometimes prohibitively expensive. Electrical heaters can be lowered with a single cable, can provide excellent temperature control, and can be reused repeatedly. There is, however, a depth limitation because of electrical power losses in the cable.

Chemically enhanced ignition does not have a depth limitation but may require handling and storage of dangerous materials. Fuel packs are not recommended because of poor temperature control and nonuniform ignition across the entire reservoir thickness. Well damage from elevated temperatures and plugging by particulate matter may occur.

Steam may be used to locally increase reservoir temperature and facilitate auto ignition. It suffers from depth limitation because of wellbore heat losses, but when the conditions are right, it can be a very simple and effective method for ignition.

The References section includes details of design and implementation of the above methods.

Well Design and Completions

ISC wells must be designed to account for several factors amplified by the combustion, namely high temperature, corrosive environment, and sand and clay control. Safe operations should be the primary concern.

Typical well designs for injection and production are shown in Figs. 16.15 and 16.16. Completion type and design depends on the reservoir being considered. Laboratory testing for sand control and completions can help to determine the best completion technique for a given field. Care must be taken to cement the wells properly. There are cement formulations that are stable at high temperatures.[20] Openhole completions may be used in conjunction with slotted liners, screens, gravel packs, or various other sand and clay control methods. To maximize productivity, producing wells should be completed toward the bottom of the zone of interest to take advantage of gravity drainage and avoid hot gases as long as possible. Rat holes have been used successfully in certain heavy-oil combustion projects to increase the effect of gravity drainage.[21]

Injection and Production Practices

Safe air injection requires that the surface injection equipment and the injection well are free of hydrocarbons. All lubricants used in compression and downhole operations should be synthetic or nonhydrocarbon types. All equipment, tools, lines, tubing, work strings, and injection strings must be clean and hydrocarbon free. Personnel at all levels should be aware of the importance of preventing hydrocarbons in the injection wells. As a safety measure to protect injection wells if the compressor is shut down, a system to prevent backflow of oil from the formation must be present at every injection well.

Downhole temperatures in producing wells increase as displaced oil, hot water, and steam fronts reach the well. Producers are preserved by downhole cooling and proper material selection. Fig. 16.17 provides an estimate of the water requirements to maintain bottomhole temperature no higher than 250°F as a function of oil and water production rate and formation flowing temperature. Significant additional oil recovery can be obtained from hot wells with downhole cooling, especially if the well is completed in the lower section of the producing zone to maximize gravity segregation in the reservoir. In many cases, after the combustion front has moved through the well, it is possible to convert the former producer to a new air injector, thus realizing significant cost reductions over the life of the project.

Monitoring is crucial for proper combustion operations. In addition to testing individual producers for oil and water rates, injected fluids must be measured. Also, produced gases must be measured and analyzed to determine the efficiency of the combustion operation. Downhole temperature measurements are essential to calculate the size and location of the burned zone. Flowline temperatures can indicate thermal stimulation or downhole problems.

Combustion projects generate waste water, flue gases, and pollutants from compression and oil-handling equipment. Local pollution disposal regulations must be consulted before designing any ISC operation.

In general, environmental problems are similar to those posed by steam injection. The produced water may contain H2S and/or CO2, which may require special handling and anticorrosion equipment. Flue gases may contain hydrocarbons, H2S, CO2, CO, and other trace amounts of sulfur gases. Table 16.3[1] summarizes the various pollution-control systems suitable for combustion projects and their recommended applications. Sarathi[1] also provides detailed descriptions of the various types of systems and their uses. Other problems that can be encountered are sand production, corrosion, emulsions, well failures, and compressor failures.

Field Experience

ISC has been used in the field since 1920. In the U.S., more than 230 projects have been implemented. Many of those were technically and economically successful. Unfavorable reservoir and fluid characteristics, poor design, and engineering or operational problems caused failures. Most of the failed projects were small pilot projects implemented in unfavorable 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 U.S. are large heavy-oil projects, while the current trend in the U.S. is to use ISC in deep, lighter-oil reservoirs in which waterflooding and steamflooding are not effective. Brief comments on these projects follow.

Heavy Oils

If we define heavy oil as under 20°API, 19 projects using ISC 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.[22]
  • 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 narrative, 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 ISC projects.[23][24]
  • 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.[25][26]
  • Projects in Russia, Kazakhstan, and Azerbaijan are not very well described in Western literature.[27]
  • The Albanian project of Kasnice is described in Marko et al.[28]
  • Batrum in Canada is a successful project using horizontal wells as producers. The Eyehill field is another project with horizontal wells.[26][29] Wabaska also uses the same concept of horizontal wells as producers.[30] Horizontal wells in ISC operations have been successfully used in Canada since 1993.

Cyclic applications such as pressure-up and blowdown, have been described.[30][31] 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.[31] 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.

U.S. projects at Bellevue and Midway-Sunset have been described.[26] More details on the Midway-Sunset project can be found in Hoffmann.[32] Ramey et al.[21] describe the Belridge project as an economic success.

ISC 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.[33][34] The additional literature covering the special handling methods and additional precautions needed for enriched air injection is listed in the References section. Commercial application of the oxygen technology has been limited because of oil-price variations.

Light Oils

ISC is used in light-oil reservoirs for two different purposes:

  • To reduce the viscosity of unconventional light oils such as Demjen in Hungary[35] 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 parafinic 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,[36] 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,[37] and Horse Creek. In those cases, combustion allows exploitation of thin reservoirs with large well spacing.

Screening Guidelines

ISC is a complex process; it combines the effects of steamdrive, hydrocarbon miscible and immiscible flooding, immiscible gas drive, and hot and cold waterflooding. 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.

ISC 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, Ф'So, 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.


ISC 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 ISC projects must be considered. First is the large compression ratio and associated costs required to inject air into the formation. Second is the planning and design requirements for a combustion project; these are more difficult than for steam injection. Third is extensive laboratory work to assess fuel availability, air requirements, and burning characteristics of the crude that are required before designing ISC projects. Fourth is the high degree of technical sophistication and the careful monitoring needed to ensure proper operation of a project. Fifth is the limitation of numerical simulation and other techniques that makes predictions of recovery more difficult than most other enhanced oil recovery methods.

Considerable improvements in the application of ISC 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 ISC. This process deserves consideration for many reservoirs, including those in hostile environments or those not amenable to other recovery methods.


a, b, d, f = stoichiometric coefficients similar to those in Eq. 16.3
A = Arrhenius rate constant
cp/cv = heat capacity ratio
Cf = concentration of fuel, kg/m3
E = activation energy, kJ/mol
Hc = heating value, Btu/lbm fuel
K = reaction rate
m = CO2/CO atomic ratio
m = CO2/CO concentration ratio produced
n = hydrogen/carbon atomic ratio of fuel
Np = oil produced, m3
(O2)prod = oxygen concentration produced
RTENOTITLE = oxygen partial pressure, Pa
R = 0.00831 universal gas constant, kJ/mol °K
RC = reaction rate of crude, kg/m3s
Sf = oil saturation burned, fraction
So = oil saturation, fraction
Soi = initial oil saturation, fraction
Swf = water saturation resulting from the combustion process, fraction
T = absolute temperature, °K
T1 = initial reservoir temperature, °F
T2 = final reservoir temperature, °F
Vb = volume burned, m3
Vp = volume of the pattern, m3
W = fuel availability
Wp = water produced, m3
Ф = porosity, fraction
μ = oil viscosity


  1. 1.00 1.01 1.02 1.03 1.04 1.05 1.06 1.07 1.08 1.09 1.10 1.11 Sarathi, P. 1999. In-Situ Combustion Handbook Principles And Practices. Report DOE/PC/91008-0374, OSTI ID 3175 (January).
  2. 2.0 2.1 2.2 2.3 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. 4.0 4.1 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.
  5. 5.0 5.1 Bousaid, S. 1989. Multiple-Quenched Fireflood Process Boosts Efficiency. J Pet Technol 41 (11): 1202-1209. SPE-16739-PA.
  6. 6.0 6.1 6.2 6.3 Mamora, D. et al. 1993. Kinetics of in-situ combustion. Report No. DOE/BC/14600-51 (DE93000152) SUPRI TR 91. Washington, DC: US Dept. of Energy.
  7. Burger, J.G. 1972. Chemical Aspects of In-Situ Combustion - Heat of Combustion and Kinetics. SPE Journal 12 (5): 410-422. SPE-3599-PA.
  8. 8.0 8.1 Moore, R.G. 1993. New Strategies For In Situ Combustion. J Can Pet Technol 32 (10). PETSOC-93-10-01.
  9. Fassihi, M.R., Brigham, W.E., Ramey, H.J.J. et al. 1984. Reaction Kinetics of In-Situ Combustion: Part 2—Modeling. SPE J. 24 (4): 408–416. SPE-9454-PA.
  10. 10.0 10.1 Moore, R.G. et al. 1995. A comparison of the laboratory in-situ combustion behaviour of Canadian oils. Proc., 6th UNITAR Conference, Houston, February.
  11. Bardon, C. and Gadelle, C. 1977. Essais de laboratoire pour l’etude de la combustion in-situ. Paper presented at the 1977 French Soviet Symposium on Enhanced Oil Recovery, Moscow, May.
  12. Leaute, R.P. and Collyer, C.J. 1984. Laboratory studies of in situ combustion with cold lake crude. Paper 5 presented at the 1984 Annual
  13. 13.0 13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 Dew, J.N. and Martin, W.I. 1965. How to calculate air requirements for in-situ combustion. Petroleum Engineer (December and January).
  14. 14.0 14.1 14.2 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).
  15. 15.0 15.1 Gates, C.F. and Ramey Jr., H.J. 1980. A Method for Engineering In-Situ Combustion Oil Recovery Projects. J Pet Technol 32 (2): 285-294. SPE-7149-PA.
  16. 16.0 16.1 16.2 Brigham, W.E., Satman, A., and Soliman, M.Y. 1980. Recovery Correlations for In-Situ Combustion Field Projects and Application to Combustion Pilots. J Pet Technol 32 (12): 2132-2138. SPE-7130-PA.
  17. Shallcross, D.C. 1989. Devices and Methods for In-Situ Combustion Ignition. Report No. DOE/BC/14126-12 (DE 89000766). Washington, DC: US Dept. of Energy.
  18. Burger, J.G. 1976. Spontaneous Ignition in Oil Reservoirs. SPE Journal 16 (2): 73-81. SPE-5455-PA.
  19. Tadema, H.J. and Weidjeima, J. Spontaneous ignition of oils. Oil & Gas J. 68 (50).
  20. Smith, D.K. 1976. Cementing, Vol. 4. Richardson, Texas: Monograph Series, SPE.
  21. 21.0 21.1 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.
  22. 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.
  23. Machedon, V. 1993. Suplacu de Barcau field: 28 years of in situ combustion. Proc., 7th European Symposium on Enhanced Oil Recovery, Moscow.
  24. 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.
  25. 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.
  26. 26.0 26.1 26.2 Moritis, G. 1998. EOR Oil Production Up Slightly. Oil & Gas J. (20 April): 49.
  27. 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.
  28. 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.
  29. 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).
  30. 30.0 30.1 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.
  31. 31.0 31.1 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.
  32. 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.
  33. 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.
  34. 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.
  35. 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.
  36. 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.
  37. 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).

General References

Alexander, J.D., Martin, W.L., and Dew, J.N. 1962. Factors Affecting Fuel Availability and Composition During In-Situ Combustion. J Pet Technol 14 (10): 1154–1164. SPE-296-PA.

Bahtia, A.K. 1998. Reservoir management of heavy oil reservoirs of North Gujarat. Proc., 7th UNITAR Intl. Conference on Heavy Crude and Tar Sands, Beijing.

Basham, M. 1999. Planning an in situ combustion project: Cymric field, California. Proc., PTTC Meeting, Bakersfield, California.

Burger, J.G. and Sahuquet, B.C. 1973. Laboratory Research on Wet Combustion. J Pet Technol 25 (10): 1137–146. SPE-4144-PA.

Carcoana, A. et al. 1975. Balayage et recuperation d’un gisement d’huile lourde par combustion in situ. Proc., Colloque Int. sur l’exploitation des hydrocarbures, Paris.

Cato, R.W. and Franka, W.A. 1968. Getty Oil Reports Fireflood Pilot is Successful Project. Oil & Gas J. (12 February).

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.

Coats, K.H. 1980. In-Situ Combustion Model. SPE Journal 20 (6): 533-554. SPE-8394-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.

Craig Jr., F.F. and Parrish, D.R. 1974. A Multipilot Evaluation of the COFCAW Process. J Pet Technol 26 (6): 659-666. SPE-3778-PA.

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

Dietz, D.N. and Wijema, J. 1968. Reverse combustion seldom feasible. Prod. Monthly (May).

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.

Fassihi, M.R. 1982. Analysis of fuel oxidation on in-situ combustion oil recovery. PhD thesis, Stanford U.; U.S. DOE Report DOE/ET/12056-26, US Dept. of Energy, Washington, DC (August).

Fattahi, B. 1999. Pyramids Hills Project, Mt. Poso Field, California. Aera Energy, 1999 PTTC Meeting, Bakersfield, California.

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.

Galas, C.M.F. and Ejlogu, G.C. 1993. Enhancement of In-Situ Combustion by Steam Stimulation of Production Wells. SPE Res Eng 8 (4): 270-274. SPE-22646-PA.

Garon, A.M. and Wygal Jr., R.J. 1974. A Laboratory Investigation of Fire-Water Flooding. SPE Journal 14 (6): 537-544. SPE-4762-PA.

Gates, C.J. and Ramey, H.J. Jr. 1958. Field Results of South Belridge Thermal Recovery Experiment. Trans., AIME 213, 236.

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.

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.

Koch, R.L. 1965. Practical use of combustion drive at West Newport field. Pet. Eng. January.

Martin, W.L., Alexander, J.D., and Dew, J.N. 1958. Process Variables of In Situ Combustion. Trans., AIME 213, 28.

Meldau, R.F., Shipley, R.G., and Coats, K.H. 1981. Cyclic Gas/Steam Stimulation of Heavy-Oil Wells. J Pet Technol 33 (10): 1990-1998. SPE-8911-PA.

Moss, J.T., White, P.D., and McNeil, J.S. Jr. 1959. In Situ Combustion Process—Results of a Five-Well Field Experiment in Southern Oklahoma. Trans., AIME 216, 55.

Olsen, D. and Sarathi, P. 1994. Field application of in- situ combustion. Report No. NIPER/BDM 0086. Washington, DC: US Dept. of Energy.

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.

SI Metric Conversion Factors

°API 141.5/(131.5 + °API) = g/cm3
bar × 1.0* E + 05 = Pa
bbl × 1.589 873 E − 01 = m3
Btu × 1.055 056 E + 00 = kJ
cp × 1.0* E − 03 = Pa•s
ft × 3.048* E − 01 = m
ft3 × 2.831 685 E − 02 = m3
°F (°F − 32)/1.8 = °C
°F (°F + 459.67)/1.8 = K
kW-hr × 3.6* E + 00 = J
lbm × 4.535 924 E − 01 = kg
psi × 6.894 757 E + 00 = kPa


Conversion factor is exact.