Discussion of In-Situ Combustion—An Update of Field Experience

Note From the Executive Editor

The process of developing technology is often associated with persistence, and good practice of science and engineering, and sometimes a bit of luck. In-situ combustion (ISC) is an example of such technologies in its “growing pain” stage, which normally involves cycles of trial, critical debating, and more trial. In the JCPT January issue of this year, we published a review article by scientists at Saskatchewan Research Council (SRC) on the technology of ISC. We subsequently received a feedback letter from Alex Turta, who has spent a large part of his research career on this technology and its applications in the field. In his feedback, Turta provided a summary of what has been performed in the field, along with his analysis and comments. I believe this is a good supplement to the original article.

Jian-Yang Yuan, PhD, Osum Oil Sands Corporation

Executive Editor, JCPT



Feedback on the article “In-situ combustion—An Overview”, published in JCPT January 2015. First of all, I congratulate the Executive Editor for the initiative to open the new session “The Technical Report,” which is aimed at publishing a series of updating papers regarding what is new in technology development relevant to the petroleum industry. Secondly, congratulations are due to the SRC for the high-quality review provided; most of the important progresses made over the years have been clearly outlined in the review. 

The ISC process is a complex process, and compared with other enhanced-oil-recovery (EOR) methods, it requires by far more planning and preparation, even if only experimentally applied. Unlike other EOR methods, people applying ISC are supposed to possess a relatively high degree of understanding; if the knowledge level is sufficient, the complexity of the process can be handled. The long-term commitment of the company is also an important factor for success.  

In the last decades, new oil-field techniques, new field equipment (mainly in the air compression area), and improved understanding of the process, of its merits and limitations, opened new possibilities for ISC application; it has been realized that the additional effort in understanding the complexities of the ISC process is worthwhile and the rewards can be high.

The goal of the present short article is to complement the mentioned overview with some specific details and, more importantly, to add some new or consolidated knowledge/know-how in the area of field application of the ISC process to the heavy-oil reservoirs; the updating in the area of ISC laboratory testing and simulation are beyond the scope of this article. The only mention is that positive laboratory tests do not guarantee the success of field application; the success can be indicated only by the ISC field test, itself.

Stability of the ISC Process. ISC is a relatively stable process. For an ISC process with a strong ISC front, interruption of air injection for weeks or even months does not lead to extinction of the active ISC front (Turta 2013a, b). This stability is higher when the interruption is made later in the life of project. Also, the stability increases for higher reservoir temperatures. At reservoir temperatures higher than 60 to 70°C—when the spontaneous ignition is possible—the interruption can be as long as is desired.  

Overriding and Channelling as Causes for Low-Volumetric Sweep Efficiency. It is true that ISC front (and therefore the air) does not channel or override with the same ease as it would if only flue gas were injected. However, there are still channelling and pronounced gravity override phenomena and they lead to a small volumetric sweep efficiency. It is acknowledged that for normal layers, with a net thickness larger than 8 to 10 m, the volumetric sweep efficiency is general low, less than 30 to 35%.

Generally, the overriding tendency is so strong that even in case there is a higher permeability layer at the bottom of formation, eventually—at a large distance from the air-injection well—the burned zone is found toward the top of the formation. The gravity override phenomenon is manifested in two ways: (1) the burned zone develops under the top of the formation (including the case of a flat formation) and (2) the tendency of this under-the-top burned zone to preferentially develop toward updip directions, exactly as in a gas injection. Because of this phenomenon, the ISC application to formations displaying a high-permeability layer at the top of formation is extremely difficult and, by far, more caution should be exercised in this situation. Application of wet ISC may alleviate to some extent this problem, but the performance will be considerably lower.

Because of the phenomena described, the field operation using the “pattern system” is cumbersome and difficult, as frequently premature breakthrough of the ISC front in the updip producers occur. The problem is alleviated significantly by switching from the patterns to the line-drive system and starting with a peripheral line drive located in the most updip position. The line drive can be applied either as an “advancing line drive” or “crestal air injection.” While in the crestal injection, the injectors remain the same for the duration of the project, in the advancing line drive, and the advancement of the row of injectors toward more virgin areas takes place.

As hinted previously, application of wet ISC (both in patterns or in line-drive configurations) can further alleviate the channelling problems. An example of wet ISC applied in a line-drive configuration has been offered by the successful Balol commercial project in India for 17 years (Roychaudhury et al. 1995; Chattopadhyay et al. 2004). While in US, the Bellevue commercial project of Texaco was operated in patterns for longer than 10 years (Joseph and Pusch 1980; Sheng 2013). Both are considered economically successful wet ISC projects. Generally, the value of the water/air ratio (WAR) used in these two commercial operations have been relatively low—up to 2 L/sm3—constituting a moderate wet ISC process. However, in the case of high-permeability reservoirs of high pressure, the WAR can take higher values—up to 4 to 5 L/sm3—without any danger of ISC extinction.

 Line-Drive Vs. Pattern System. A crucial decision an ISC operator faces is the location of the first ISC pilot on the structure. Many times, this decision influences the entire deployment of the project and can actually spell the success or failure of a project.

Usually, after the ISC piloting, the pilot area is integrated in a semi- or directly commercial operation; therefore, further development takes place nearby and is linked with the pilot area. Location of the pilot at the uppermost position is of paramount importance. In the past, several projects that did not pay attention to this elementary rule paid a heavy price. This is so important because with the location of pilot updip, once the pilot is over, all the options are open for commercial operation: crestal injection, advancing line-drive operation, or the pattern system. Therefore, even when using the pattern system, the commercial exploitation should start from the most updip position.

Location updip of the pilot is also extremely important in having the ability to make a reliable evaluation at the end of the piloting period. Air-incremental/oil ratio (AOR) and incremental oil recovery (% OOIP) can be calculated easier, because as a confined region can always be defined. A nonupdip location is often associated with an unreliable evaluation and an impossibility to make a clear decision related to the technical and economic success of the pilot; unfortunately, this situation did happen frequently in the past.  

 The Need for Preheating. Conventional ISC essentially constitutes a gas-injection process, which, to some extent, benefits oil-viscosity reduction. In principle, ISC consists of successive displacement fronts, the most important being flue gas front, hot water and steam fronts, light oil (as a solvent) front, and eventually the direct displacement by the ISC front, itself. The benefit of oil-viscosity reduction is observed mainly for the oil produced from the unburned zone, located under the burnt out zone.

Conventional ISC involves a straight horizontal displacement; hence, it is a long-distance displacement of heavy oils. The displaced heavy oil downstream of the front forms an oil bank, but at the same time cools down quickly; it has to flow eventually through a cold region. This creates a pronounced relative permeability effect, a blocking effect, and the air injection is chocked off causing potentially the project to be abandoned because of injectivity problems. The experience acquired in the last 60 years showed that if the original oil viscosity is higher than 1,500 to 2,000 cp, then the preheating by cyclic steam stimulation (CSS) is necessary. The combination of ISC with CSS constitutes the key for the successful commercial operation at Suplacu de Barcau in Romania for more than 44 years; CSS is systematically applied for the producers of second and third row, ahead of the linear ISC front (Panait-Patica et al. 2006).   

All in all, the preheating can be achieved simultaneously with the (e.g., in the Suplacu de Barcau case) or previous to the ISC application. For the last option, the best example is the semicommercial ISC project in the Morgan reservoir (Marjerrison and Fassihi 1995). In this case, the ISC was applied after a 5-year period of intensive CSS operations, with up to eight to nine CSS operations for each well; the last CSS operations were carried out by injecting steam and air instead of steam only. The results in terms of AOR and oil recovery were good, with a significant upgrading of the produced oil as a bonus. The process interpretation is complicated by the fact that pressure-cycling ISC process (alternative long periods of injection and noninjection with producers on, continuously) was applied instead of a continuous ISC process. The explanations for the phenomena responsible for this satisfactory performance and the consistent upgrading do not exist yet, and no other investigations to clarify this process have been undertaken.

 Effect of Reservoir Temperature at the Time of ISC Application—Tertiary Recovery. Commercial application of ISC to high-depth, high-temperature reservoirs containing light oil in Williston basin in the US came as a surprise by the 1980s. It is now known under a slightly euphemistic name of “air injection” or high-pressure air injection (HPAI). The HPAI process is not the objective of this article.

The HPAI process was possible because of the high-reservoir temperature, which made possible initiation of ISC through spontaneous ignition. Without this advantage, an additional phase, artificial ignition, has to be considered, which can complicate and make the process more expensive and less stable in its future development. Today, there is a tendency to apply a similar process to heavy oils contained in the high-depth, high-temperature reservoirs; in this case for application, both knowledge fof ISC in heavy-oil reservoirs and from air injection in high-depth, high-temperature reservoirs containing light oil is necessary. A counterintuitive outstanding feature exists in this case; the higher the reservoir temperature and reactivity of the oil, the lower the peak temperatures in the ISC front can sustain the process. The direct consequence is that the risks of damaging the production wells are almost eliminated totally. Two commercial operations, Midway Sunset (Couniham 1977; Curtis 1989; Northrop 1994) and West Heidelberg (Huffman et al. 1983), convincingly confirmed that the highest temperature recorded by a production well did not exceed 250°C in more than 20 years of operation. Other commercial operations confirm this finding. By contrast, in Suplacul de Barcau and Bellevue heavy-oil ISC operations (reservoir temperature approximately 20°C) 15 to 20% of production wells are damaged by ISC interception and need replacement wells. The undamaged production wells is a positive aspect. However, there is a negative outcome related to this aspect as well; the monitoring of the position of the ISC front becomes more difficult; and related to this, the application of the advancing line drive may become more difficult.

This phenomenon is actually similar to the HPAI projects in which damage of production wells have never been reported. This is because the peak temperature (Tpeak) in the light oil ISC is low in the range of 270 to 380°C. Oxygen consumption during a typical ramped temperature oxidation (RTO) laboratory test for heavy oils and light oils is shown in Fig. 1 (Gutiérrez et al. 2009). It can be observed that for light oils, there is enough fuel and the oxidation reaction is high enough in the low-temperature range that there is no need for higher values of Tpeak to sustain the ISC process. It is possible that some heavy-light oils (viscosity range of approximately 60 to 600 cp) have oxidation characteristics similar or close to those of light oils, and in this case, lower values of Tpeak are possible. Laboratory RTO tests can give an indication explaining this.

Although an appropriate ISC process as a post-steam-assisted-gravity-drainage (SAGD) method has not been developed yet, the application of ISC as post-steam drive tertiary operation has advanced considerably, and it is close to becoming commercial. Two semicommercial operations of this type in China and Romania were highly successfully (Turta 2013a, b; Jihong et al. 2013). For both projects, oil recovery increased from approximately 35% to 60 through 70%, while final AOR was less than 2,000 sm3/m3. In both cases, the high reservoir temperature (at least approximately 90°C) at the time of ISC initiation was the first factor responsible for the success; the second factor was application of line drive. In cases where the oil recovery by steam drive is more than 50%, the ISC as a post-steam flood has not been field tested and proved/demonstrated yet.

It is expected that in the next decades, the ISC will make the biggest progress and it will see its most widespread application/deployment in the heavy-oil, high-depth reservoirs and as a tertiary process after steam-injection-based operations. To speed up the progress in this direction, efforts should be made to improve the laboratory testing. The laboratory tests, ideally, should provide quantitative information about the rock/oil oxidability and even the minimum level of Tpeak at which the ISC field process is self-sustaining. Eventually, for a certain reservoir rock/oil couple, the following sequence may become a reality:

  • Conduct the RTO tests and determine accurate kinetic parameters;
  • Using these kinetic parameters, run the simulator for a laboratory combustion tube test (with rock/oil of the specified reservoir) and determine the value of Tpeak in the stabilized regime;
  • Conduct the laboratory combustion tube test to validate the value of Tpeak in the stabilized regime; and
  • Design the field experiment, including the appropriate well completion.

So far, the commercial application of ISC as a post-waterflood, tertiary method in heavy-oil reservoirs has not been fully proved. The large-scale commercial operation in Videle-Balaria, Romania, (Turta and Pantazi 1986; Machedon et al. 1993) was marginal in efficiency; the AOR took high values (5,000 to 6,000 sm3/m3). In this case, the reservoir dip and temperature were relatively low; temperature was approximately 46°C. It is expected that, in higher temperature reservoirs with a good dip, the process still has chances to become commercial.

Use of Horizontal Wells in Combination With ISC Process. Use of horizontal wells as producers in conventional ISC operations, either during active ISC operation or later on (when the process was already shut-in), has been recorded in at least four projects, although only three projects (two Canadian and one Chinese project) are documented (Farquharson and Thornton 1986; Pebdani et al. 1994; Sun 2012). The first factor for success is the placement of the horizontal section of the well compared with the existing ISC front (or former front). If placed right ahead of the front, performance can be exceptional; far ahead of the front results in mediocre performance, and with interception of the burnt out zone (part of horizontal section behind the front) the performance deteriorates considerably, and, sometimes, only flue gas may be produced. Therefore, the length itself is not important; what is extremely important is the placement relative to the burnt-out zone.

 Using the horizontal producers in an effort to overcome the mobility restrictions (blockage) in very heavy-oil reservoirs has led to the development of short-distance oil displacement (SDOD) methods (Turta and Singhal 2004) [e.g., toe-to-heel-air-injection (THAI), combustion override split-production horizontal well (COSH), and SAGD processes]. Typical to SDOD processes is the existence of a mobile-oil zone (MOZ); oil is no longer flowing through the cold region but through the MOZ, which has a relatively high temperature.

The COSH process (Kisman and Lau 1994) has not been field tested yet. In the last 9 years, the THAI process has been tested in two fields in conditions encompassing conventional heavy oils and oil sands. In these cases, only the direct line-drive (DLD) configuration was tested. However, the original THAI process (Greaves and Turta 1997) involves two options; DLD and staggered line-drive (SLD) configuration. The field tests recorded so far proved the technical validity of THAI applied in a DLD configuration.  Economic validity; hence, full commercialization, may come once the second THAI configuration (SLD configuration) is field tested. The THAI-related knowledge acquired during more than 20 years of THAI investigations is extremely important because any attempt to use horizontal well producers in a present conventional ISC or in developing a new ISC process as a follow up to a steam-injection-based process has to rely heavily on it. More precisely, in these cases, to have an in-depth understanding of the self-healing feature of THAI, namely the local plugging of horizontal section of horizontal producer, is crucial.    

Use of the horizontal wells as air-injection wells began in the Williston basin for air injection in deep-light oil reservoirs of low permeability (Sheng 2013), while their use in an ISC process conducted in a heavy-oil reservoir was recorded in just one test, in Peace River, Alberta (Thornton et al. 1996). In this case, a horizontal well was used for air injection for 4 months in an attempt to cycle the ISC operation. On the basis of the scant information provided, it can be concluded that the use of the horizontal wells as air-injection wells in an ISC process cannot be ruled out totally; new methods for ensuring the complete safety of operation may be developed in the near future.


Credit is given to all my friends from India, US, China, Canada, Romania, and Colombia for their contributions to the development of ISC. 


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Submitted 30 March 2015 by Alex Turta, A T EOR Consulting Incorporated.


Author’s Response

I wish to thank Alex Turta for his feedback on our original article. He has provided an excellent summary of the operating principles that have been established through past field trials, and of some of the opportunities that could still be developed, especially in applications to heavy oils. I also agree wholeheartedly with him that we cannot yet guarantee the technical success of ISC projects without a field pilot, and that further development of laboratory testing and reaction kinetics—which I believe would go hand-in-hand with improved confidence in the simulation of ISC—would speed up the adoption of ISC processes.

Norman Freitag, SRC