Reservoir heterogeneity

By 1980, research and development shifted from relatively inexpensive surfactants such as petroleum sulfonates to more cosdy but more effective surfactants tailored to reservoir and cmde oil properties. Critical surfactant issues are performance in saline injection waters, adsorption on reservoir rock, partitioning into reservoir cmde oil, chemical stabiUty in the reservoir, interactions with the mobiUty control polymer, and production problems caused by resultant emulsions. Reservoir heterogeneity can also greatly reduce process effectiveness. The decline in oil prices in the early 1980s halted much of the work because of the relatively high cost of micellar processes. 

Riley, R. A., Harper, J. A., Baranoski, M. T., Laughrey, C. D. Carlton, R. W. 1993. Measuring and Predicting Reservoir Heterogeneity in Complex Deposystems The Late Cambrian Rose Run Sandstone of Eastern Ohio and Western Pennsylvania. Appalachian Oil and Natural Gas Research Consortium, Morgantown, West Virginia. 

The front is inherently unstable, however, and this is often studied by a linear stability analysis. Infinitesimal perturbations are applied to all of the variables to simulate reservoir heterogeneities, density fluctuations, and other effects. Just as in the Buckley-Leverett solution, the perturbed variables are governed by force and mass balance equations, and they can be solved for a perturbation of any given wave number. These solutions show whether the perturbation dies out or if it grows with time. Any parameter for which the perturbation grows indicates an instability. For water flooding, the rate of growth, B, obeys the proportionality... 

The problems of combining flow instabilities with a description of reservoir heterogeneities in a realistic unified treatment is currently of great interest for all types of EOR. Chapter 3 of this book describes the beginnings for new methods of introducing the heterogeneities of a reservoir into simulations of the fluid flow. Treatment of the fully coupled problem, i.e., flow instabilities with three fluids in a field-scale natural reservoir, will require many years of research. 

Arya, A., 1986. Dispersion and Reservoir Heterogeneity. Ph.D. dissertation. University of Texas at Austin. 

Arya, A., Hewett, T.A., Larson, R.G., Lake, L.W, 1988. Dispersion and reservoir heterogeneity. SPE Reservoir Engineering (SPERE) (February), 139-148. 

Miall, A.D. (1988) Reservoir heterogeneities in fluvial sandstones lessons from outcrop studies. Bull. Am. /lii. Petrol. Geol., 72, 682-697. 

This study provides additional new information on using produced water from a different type of EOR project—immiscible cyclic COj. The produced water chemistry is used to ascertain well-bore scale potential, relative rates of mineral dissolution and reservoir heterogeneity. Much of the information and methodology contained herein applies equally well to other types of EOR or to other reservoirs where produced water chemistry is monitored regularly. Also, the information about mineral dissolution has applications for any study involving mineral dissolution and diagenesis caused by low pH and to the upscaling of experimental laboratory results. 

Carbonate cement dissolution caused by cyclic C02-enhanced oil recovery treatments can provide information in several areas. From this study, which examined mineral dissolution, well-bore scale and reservoir heterogeneity/geometry, the following conclusions are drawn. 

When C02 foam is used for mobility control, only uneconomic amounts of oil would be expected to remain in the pore space behind a matched-mobility stabilized front. Because of the well-to-well nature of the displacement, however, and because of the presence of reservoir heterogeneities, all segments of the front will not arrive simultaneously at the producers. Consequently, foam will not prevent the breakthrough of the injection fluid before complete recovery. However, the use of C02 foam should increase the recovery that will be obtained from the field before its abandonment is mandated by the rising gas and water cut. 

The reports of the enhanced oil recovery projects concluded that the reservoir heterogeneities is the most frequent cause for failure of enhanced oil recovery processes which involve foam and surfactant flooding. It was deserved that the reservoir heterogeneity was much more dominant than expected. Geologic and permeability heterogeneities were the most probable cause of the low recovery efficiency realized by Goodrich and Watson The wettability of the pore surface affects the recovery efficiency, but this effect is poorly understood because it is almost impossible to determine which portions of the surface are oil-wet and which ones are water-wet in the subsurfaces. The wettability of the reservoir rocks can be influenced by the injection of surfactant solution for foam flooding. 

ARYA, A. HEWITT, T. A., LARSON, R. and LAKE, L. W., "Dispersion and Reservoir Heterogeneity", SPE 14364, presented at 60th Annual Fall Conference on SPE, Las Vegas, Nevada, 22-25 September, 1985. 

Below the bubble-point, pressure gas percolates out of the oil phase, coalesces and displaces the crude oil. The gas phase, which is much less viscous and thus more mobile than the oil phase, fingers through the displaced oil phase. In the absence of external forces, the primary depletion inefficiently produces only 10 to 30 percent of the original oil in place. In the secondary stage of production, water is usually injected to overcome the viscous resistance of the crude at a predetermined economic limit of the primary depletion drive. The low displacement efficiencies, 30 to 50 percent, of secondary waterfloods are usually attributed to vertical and areal sweep inefficiencies associated with reservoir heterogeneities and nonconformance in flood patterns. Most of the oil in petroleum reservoirs is retained as a result of macroscopic reservoir heterogeneities which divert the driving fluid and the microscopically induced capillary forces which restrict viscous displacement of contacted oil. This oil accounts for approximately 70 percent, or 300 x 10 bbl, of the known reserves in the United States. 

As a second example, calculations were repeated with separations between dark streaks doubled. Because the overall averaged permeabilities are decreased relative to the values just considered, lower volume flow rates should result we consistently obtained, 0.62 as opposed to 0.69, 0.67 versus 0.80, 0.70 versus 0.88, and 0.67 versus 0.87, but streamline convergence was again observed. Again, the cumulative effects of locally weak reservoir heterogeneities and nonuniformities turned out to be important in changing streamline orientation. 

Schurz, G.F. etal. Polymer-Augmented Waterflooding and Control of Reservoir Heterogeneity, paper NMT 890029 presented at the 1989 New Mexico Tech Centennial Symposium, Socorro, NM, Oct. 16-19. 

Oil recovery by polymer flooding is influenced by reservoir heterogeneity not only through its effects on crossflow, but also through the dependence of polymer retention, inaccessible pore volume, and polymer shear degradation on permeability. This paper describes a simulator that accounts for all these factors and includes experimental data, obtained using field and Berea cores, that demonstrate the permeability dependence of these factors. 

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