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Primary and Thermal Production of Heavy OilsSo-called cold production of heavy oil is attractive because steam injection is costly due to the operating and capital expenses for steam generation facilities. Cold production signifies substantial primary recovery on the order of 10-15% from heavy-oil reservoirs. Most cases of significant cold production are associated with foamy crude oil and horizontal wells (Smith 1988). Here, gas released from solution during pressure depletion remains dispersed as small bubbles rather than uniting to form a single phase. With foamy crude oil, the gas-oil ratio (GOR) is lower and the oil productivity of a well is increased over the unfoamed case (Maini et al. 1993). 
A key to developing a mechanistic understanding of foamy-oil behavior is to delineate bubble growth, interaction, and flow mechanisms at the pore level. These are unknown for foamy heavy oil. Here, we will use micromodels with representative sandstone networks (Hornbrook et al. 1991) to observe bubble size, nucleation, growth, and flow at the pore level. Crude oil saturated with methane as well as non-foaming mineral oil will be employed. The micromodels will be subjected to a declining pressure and the dynamics of heavy-oil solution gas drive observed. By using various types of oil (viscosity, acid number, and intermediate versus heavy), we hope to delineate crude-oil conditions that are conducive to the formation of foamy oil. As pressure and temperature are important to crude-oil behavior, a major portion of this effort will be in the design of an apparatus to conduct experiments at relevant temperatures and pressures. Companion experiments will also be conducted in sands and sandstone. The purpose of the experiments is to measure the evolution of oil and gas saturation as well as pressure while undergoing primary production of foaming and non-foaming heavy crude oils. Production rate will be varied to delineate critical rates of production necessary for foamy oil generation. Porous media will be scanned along the length of the core rather than conventional cylindrical cross sections. In this manner, it should be possible to visualize core-spanning gas paths if they develop. A visual cell will be used at the outlet to gauge the size of mobile bubbles. Mobile bubble size can then be compared between the micromodel and porous media experiments. 
The next task is to translate the experimental observations and results from the above experimental effort into a mechanistic model for cold production of heavy oil. The model will be mechanistic and consistent with physical observations. Since unfoamed oil is a subset of foamy oil, the model will address primary production of all heavy crudes. Information on foam-bubble size and the rheology of bubble-laden crude oil will be translated into a model and subsequently tested in a reservoir simulator. Our approach will likely be a bubble population balance (e.g., (Kovscek et al. 1995)). In a population-balance method, the number density of bubbles (i.e., the number of bubbles per unit volume of gas) is tracked as a function of location and time. Number density is also referred to as bubble texture. The crux of the problem is not to write the population balance, but rather to develop the requisite mechanistic constitutive equations for gas and oil flow as well as the rate equations for the formation of gas bubbles. These equations will be developed and tested against the information and data garnered in the experiments described above. In the area of thermal oil production, we continue our active program on the flow of high temperature fluids in porous media. Currently, there are two primary thrusts. First, we are quantifying through experiment and theory the speed and extent to which steam and hot water change the permeability of low permeability, siliceous, diatomite. Recent field tests have shown that steam injection can recover substantial amounts of oil trapped inside low permeability reservoir rock (Kumar and Beatty 1995; Kovscek et al. 1997). In the case of diatomite, large internal surface area and high steam and condensate temperatures could lead to substantial rearrangement of permeability. Hot steam condensate might dissolve large amounts of silica, the silica can then transport with the aqueous phase, and silica would precipitate in a different portion of the reservoir as the condensate cools. Hence, permeability might increase near injectors and decrease within the reservoir. Our current plans call for conducting experiments with hot water injection into representative diatomite samples and to monitor the evolution of porosity with our CT scanner. Likewise the evolution of the pressure profile at a given rate will be monitored. In this way, we will measure the time evolution of permeability and porosity in a well characterized and controlled environment. The CT scanner will allow us to determine if "wormholes" develop upon injecting hot, silica-free water. Continuum and network models of the process, or both, might follow based upon the experimental results. 
The second thrust in thermal production is the effect of temperature on relative permeability. Akin et al recently demonstrated through both experiments and reservoir simulation that viscous fingering at low to moderate temperature in heavy-oil systems posed a problem for interpretation of such experiments using standard techniques such as the Johnson-Bosler-Nauman (JBN) method (Akin et al. 1999). This work shed light on the nature of the temperature effect on measured relative permeability. A logical successor is to begin a careful scaling analysis and review of all of the physical factors governing relative permeability. In such a manner, the key dimensionless groups will be identified. This will aid interpretation, understanding, and categorization of previous experiments and aid in the design of new experiments, if needed. ReferencesAkin, S., Castanier, L. M. and Brigham, W. E. (1999). "Effect of Temperature on Heavy Oil/Water Relative Permeabilities." SPE 54120, 1999 SPE International Thermal Operations Symposium, Bakersfield, CA, 17-19 Mar. 1999. Hornbrook, J. W., Castanier, L. M. and Pettit, P. A. (1991). "Observation of Foam/Oil Interactions in a New, HIgh-Resolution Micromodel." SPE 22631, 66th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Dallas, TX, October 6-9, 1991. Kovscek, A. R., Patzek, T. W. and Radke, C. J. (1995). "A Mechanistic Population Balance Model for Transient and Steady-State Foam Flow in Boise Sandstone." Chemical Engineering Science 50(23): 3783-3799. Kovscek, A. R., Johnston, R. M. and Patzek, T. W. (1997). "Evaluation of Rock/Fracture Interactions During Steam Injection Through Vertical Hydraulic Fractures." SPE Production and Facilities May: 100-105. Kumar, M. and Beatty, F. D. (1995). "Cyclic Steaming in Heavy Oil Diatomite." SPE 29623, SPE 65th Western Regional Meeting, Bakersfield, CA, March 8-10, 1995. Maini, B. B., Sarma, H. K. and George, A. E. (1993). "Significance of Foamy-Oil Behaviour in Primary Production of Heavy Oils." Jour. of Canadian Pet. Tech. 32(9): 50-54. Schembre, J. M., Akin, S., Castanier, L. M. and Kovscek, A. R. (1998). "Spontaneous Water Imbibition into Diatomite." SPE 46211, 1998 Western Regional Meeting of the Society of Petroleum Engineers, Bakersfield, CA, May 10-13, 1998 SPE. Smith, G. E. (1988). "Fluid Flow and Sand Production in Heavy-Oil Reservoirs Under Solution-Gas Drive." SPE Production Engineering May: 169-180. Energy Resources Engineering Department, School of Earth Sciences, Stanford, CA / kovscek@stanford.edu |