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In situ combustion is a thermal recovery technique where energy is generated by a combustion front that is propagated along the reservoir by air injection. Most of the previously conducted studies report thermal and fluid dynamics aspects of the process. Modeling in situ combustion process requires extensive knowledge of reservoir data as well as reaction kinetics data. Unfortunately, limited kinetic data are available on the rates and the nature of partial oxidation reactions and the high-temperature combustion reactions of crude oils and their saturate, aromatic, resin, and asphaltene (SARA) fractions. Moreover, the impact of such data on the modeling of the in situ combustion process has not been investigated thoroughly. Thus, we modeled in situ combustion experiments conducted on a 3D semi-scaled physical model that represents one fourth of a repeated five spot pattern. In all experiments a vertical injector is employed whereas, both vertical and horizontal producers have been installed to recover two different crude oils (heavy and medium). Several locations for the producers have been tried while keeping the length of the wells constant: vertical injector-vertical producer, vertical injector-horizontal side producer, and vertical injector-horizontal diagonal producer. In these experiments diagonal producers performed better than the others. We first simulated the experiments by incorporating a kinetic model that is based on grouping the products of cracking into six pseudo components as heavy oil, medium oil, light oil, two non-condensable gases and coke using a commercial thermal simulator (CMG's STARS). Four chemical reactions were considered: cracking of heavy oil to light oil and coke, heavy oil burning, light oil burning, and coke burning. Most of the experiments were history matched successfully with the exception of ones where a diagonal horizontal producer was used. We then repeated the simulations using SARA kinetic parameters. We observed that all matches were somewhat improved. We finally present a discussion of application of the models to field scale. Introduction In-situ combustion is an important enhanced oil recovery process that has been studied extensively the past 45 years. This process has been considered particularly applicable for in-situ recovery of medium and heavy oil reservoirs. In in-situ combustion, heat is generated within the reservoir by igniting the formation oil and then propagating a combustion front through the oil reservoir. The fuel necessary to sustain the combustion front is supplied by the heavy residual material or "coke" that deposits on the sand grains during distillation, thermal cracking, pyrolysis etc. of the crude oil ahead of the combustion front. Sweep efficiency during in-situ combustion is one of the most important process parameters, but which has not been extensively evaluated and is least understood. Most laboratory investigations are conducted in combustion tubes, which essentially use a vertical well arrangement and which, of course, because of their basically one-dimensional geometry, cannot provide information on either areal or vertical sweep. Information on the combustion sweep efficiency is very important for comparing process variations and also for predicting performance. 3-D scaled physical models can provide much valuable insight into the areal and vertical sweep processes and stability of the combustion front over a range of operating conditions. Results from such experiments may be used in conjunction with those from combustion tube tests to predict performance in the field, and also to validate numerical simulator models.

This study presents an experimental investigation of the effect of fractures and well configurations on the steam-assisted gravity drainage (SAGD) process in a three-dimensional model, using 12.4°API gravity crude oil. A total of eight runs were conducted, using a 30 cm × 30 cm × 10 cm rectangular-shaped box model. Temperature distributions were observed using 25 thermocouples. Three different well configurations were investigatedsa horizontal injection and production well pair, a vertical injection-vertical production well pair, and a vertical injection-horizontal production well pairswith and without fractures that provided a vertical path through the horizontal producer. The influence of fracture distribution on the steam-oil ratio (SOR) and oil recovery was analyzed using the horizontal well pair scheme, a vertical injection-horizontal production well pair, and a vertical injection and vertical production well scheme. The experimental results indicated that vertical fractures improved SAGD. Maximum oil recovery was observed during the horizontal injection-horizontal production well scheme with a fractured model, because of the favorable steam-chamber geometry. Runs showed that the location of the fractures affects the performance of the process. During the early stages of the runs, the fractured model gave significantly higher SORs than those observed in the uniformpermeability reservoir.

Wettability measurement methods, the effect of wettability on fluid distribution, and fluid flow in porous media were discussed, and the influence of rock wettability on the relative permeability and recovery of oil by waterflooding were investigated. Experimental studies were conducted on a total of 23 core plugs from two different limestone formations. Synthetic brine (NaCl solution) and mineral oil, which has a viscosity ratio of ∼10, were used as the test fluids. Core samples, saturated with synthetic brine, were flushed with mineral oil to establish the initial conditions, and the wettability of the samples was measured by the Amott−Harvey method. Test results showed that the wettability of the samples ranged from strongly water-wet to intermediately wet. Wettability measurements were repeated and showed that the Amott−Harvey wettability indices were reproducible. The effects of aging time, brine salinity, and saturation procedure on wettability were examined. Long-time aging in mineral oil altered the wettability of a water-wet core sample to intermediately wet. Unfortunately, there was only one water-wet sample, and correlation of the alteration of wettability, with respect to aging time, was not possible. Increasing the brine salinity also reduced the water wetness. However, the saturation procedure had almost no effect on the wettability of the core samples. Aging could not alter the wettability of the intermediately wet samples, by varying brine salinity and by changing saturation procedure; therefore, it was concluded that intermediate wettability was more stable than water wetness. Relative permeability and waterflood studies were conducted on core samples that had different wettability levels. In a water-wet medium, water breakthrough occurred relatively late and a considerable amount of oil was produced before the breakthrough. After the breakthrough, the rate of oil production was decreased very sharply. Decreasing the water wetness resulted in decreasing the breakthrough recovery. In the intermediately wet system, breakthrough occurred very early and most of the oil was produced after the breakthrough. Water breakthrough had almost no effect on the rate of oil production. Waterflood in the water-wet system seemed more economical, because a lesser volume of water was required to produce the same amount of oil.