Picture of Alex Turta (Available In Full Paper) Alex Turta is a project leader for Improved Oil Recovery at Alberta Research Council (ARC) in Calgary. His research interests include primary recovery of heavy oils, waterflooding of light oils, and thermal recovery methods for heavy oil. He has extensive experience of heavy oil exploitation, from laboratory to field pilots, and has undertaken international consultancy for thermal pilot evaluation. He assisted in the development of the enhanced oil recovery evaluation software PRIze. Alex holds M.Sc. and Ph.D. degrees from the University of Oil and Gas and Petroleum Engineering, Bucharest, Romania, and worked previously at the Research and Development Institute for Oil and Gas, Campina, Romania. He is a co-inventor of the THAI and CAPRI processes for heavy oil recovery and upgrading, and is a member of SPE, the Petroleum Society and the Canadian Heavy Oil Association. Picture of Dr. S. K. Chattopadhyay (Available In Full Paper) Dr. S. K. Chattopadhyay is Chief Chemist for the Oil and Natural Gas Corporation (ONGC) Ltd., India, working at the Mehsana Asset. He joined ONGC Ltd. in 1983 as a Graduate Trainee in Chemistry. Over the last 24 years at ONGC, he has gained experience working at different offshore and onshore production installations, the LPG/CSU/C2-C3 process control laboratory, onshore drilling rigs, the in-situ combustion process monitoring laboratory and, presently, he is working in a multi-disciplinary team for the monitoring, interpretation and process control of the commercial in-situ combustion process at the Balol and Santhal Fields of the Mehsana Asset, India. Dr. Chattopadhyay has presented several technical papers on the in-situ combustion process at various national and international conferences and symposiums. He graduated with a Ph.D in chemistry from the University College of Science, Calcutta University, India. Picture of R. N. Bhattacharya (Available In Full Paper) R. N. Bhattacharya is the General Manager (Reservoir) for the Oil and Natural Gas Corporation (ONGC) Ltd., India, working at the Mehsana Asset. He is presently working on the company 's commercial in situ combustion scheme in Western India. Mr. Bhattacharya has had experience working on different assets and projects for ONGC, including overseas projects. He has over 30 years of oil industry experience as petrophysicist, reservoir engineer and in contract monitoring. Mr. Bhattacharya earned an M.Sc (physics) in 1972 and M.Sc. (geophysics) from Banaras Hindu University, India. He studied reservoir engineering at the India School of Mines (ISM), India, the University of Austin and Stanford University, USA. He is the author of several technical papers and numerous technical reports. Picture of Alexandru Condrachi (Available In Full Paper) Alexandru Condrachi is a Reservoir Engineer for PETROM S. A. Member of OMV Group, E&P Central Region Division, Ploiesti. He earned a B.C., M.S. and Ph.D. degrees from the Petroleum-Gas University of Ploiesti, Romania. Picture of Wayne Hanson (Available In Full Paper) Wayne Hanson has been with the Bayou State Oil Corporation (BSOC), Bellevue, Louisiana since 1980. Initially, he served as a Petroleum Chemist, and starting from 1990, he has been Supervisor of the BSOC In-Situ Combustion Project.

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THAI, or "Toe-to-Heel Air Injection," is an integrated horizontal well process for in situ recovery and upgrading of heavy oil and tar sands bitumen. During extensive studies of the process at the University of Bath, involving more than 50 three-dimensional combustion cell tests, the process has repeatedly demonstrated robust and stable operation. However, the answer to the question: "Why does oxygen breakthrough into the toe of the horizontal well not occur," has not been fully developed. This is now all the more important since the THAI process is about to be tested in the field. In order to maintain stable propagation of the combustion front, sufficient fuel needs to be available ahead of the front. This is fundamental to the in situ combustion (ISC) process, whether in its conventional form, or THAI. When the combustion front approaches close enough to the horizontal producer well, heavy residue can drain into the well. This residue, or coke material, provides a gas seal, preventing the injected air from channeling through to the well. This paper presents post-mortem results of two THAI experiments, in which the horizontal well was cut-open to reveal the extent of heavy oil residue/coke deposition. The visual evidence is supported also by a numerical simulation of the experiment, showing the distribution of coke and oxygen through the oil layer. Introduction In situ combustion (ISC) has, theoretically, always held the promise of high potential rewards for heavy oil recovery. This is basically because, if a stable combustion front at high temperature (500 - 600 ° C) can be propagated through the oil-bearing formation, virtually all of the heavy oil it contacts is displaced. The fundamental principle of ISC, as applied to heavy oil recovery, is well known, as described by Burger et al.(1). ISC is achieved by burning a small fraction of the oil in the reservoir, which releases sufficient reaction energy to create a large increase in reservoir temperature in the combustion front zone, thereby mobilizing and displacing the oil ahead of it. The chemical reactions between oxygen and crude oil are extremely complex, principally because there are a large number of components which can undergo thermal cracking reactions. The overall complexity of the ISC process is increased because of the interaction between chemical reaction and transport processes in reservoir porous media. Although considerable understanding of the ISC process has been gained in recent years, and new guidelines and strategies for field operations have been presented(2, 3), there are still a number of concerns about the process which need to be resolved if its full operational potential is to be realized. These include:Gravity segregation, or gas overriding;Oil banking in the cold region ahead of the combustion front; and,Permeability heterogeneity. Gas overriding, due to the buoyancy effect between the combustion gases and reservoir liquids, exacerbated by permeability contrasts in the reservoir porous media, can cause severe channeling of gas through to the producer well.

Foam stability in the presence of crude oil is important to foamflood performance. Microvisual observations were made to assess the degree of foam-lamella/oil interactions occurring between a light crude oil and foams being considered for foam flooding applications in Alta., Canada. Foam behaviors ranged from quite stable, with almost no foam/oil interactions, to quite unstable, where oil was extensively emulsified and imbibed into the foam. These behaviors matched phenomenological model predictions and also were consistent with coreflood mobility reduction factors and incremental oil recoveries obtained in foam flow experiments in Berea sandstone cores at ambient temperature, low pressure, and residual oil saturation (ROS).

An in-depth analysis covering over forty foam applications in Enhanced Oil Recovery (EOR) projects and numerous production well treatment operations was conducted, to obtain insights on screening and design of such applications. Foam can be used to solve conformance problems caused by either a thief zone or gravity override; proper identification of the cause, as well as of the affected production well(s) is basic to definition of the problem. Either blocking/diverting foams or in-depth mobility control foams can be placed through the injection wells. On the other hand, foam is placed in production wells mainly to mitigate an override problem.The most important factors in foam assisted EOR projects are: (a) manner of foam placement in the reservoir (injection of pre-formed foam, co-injection foam and SAG or surfactant alternating gas foam), (b) reservoir pressure and c) permeability. While pre-formed foams are effective in the treatment of production wells, co-injection foam and SAG foam can be employed for solving specific sweep problems. For designing a steam-foam project (which is a low pressure foam application), foam quality in the range 45% to 80% should be considered. In this application, a co-injection foam is employed and the additives (surfactant and non-condensable gas) are injected intermittently (on and off), superimposed on a continuous steam injection. Injection cycles as short as 7 days are common. Under suitable conditions, an oil rate increase of 1.5 to 5 times, a decrease in water cut by 20 %, and an incremental oil recovery of 6%-12% OOIP can be achieved with this implementation. At high pressure, such as in gas miscible flooding, foam application can result in excessive mobility reduction factors, and injectivity reduction. Due to this reason, in these projects, alternate injection of surfactant solution and gas (SAG foam) is favoured over a coinjection mode of placement. Low Pressure Foam Application: Steam Drive.Out of 19 projects reviewed, 14 were in the Midway Sunset and Kern River fields in California 12-16 , where the reservoirs are shallow, with good porosity and permeability. Oil viscosity is between 1000 and 4000 mPa.s. Surfactant was injected along with a low pressure (0.7-3.5 MPa) steam injection to solve overriding problems. Patterns areas were in the range 0.5-4 ha, and at the time of foam injection, the steam drive was quite mature, having been in progress for 5 to 10 years, with a current oil recovery in the range of 30% to 60% OOIP. The most commonly employed surfactants were Chaser SD and Suntech injected at concentrations in the range of