No abstract

This paper presents a method for calculating the producing rate of a well as a function of time following steam stimulation. The calculations have proved valuable in both selecting wells for stimulation alld ill determining optimum treatment sizes. The heat transfer model accounts for cooling of the oil sand by both vertical alld radial conduction. Heat losses for any number of productive sands separated by unproductive rock are calculated for the injection. shut-in and production phases of the cycle. The oil rate increase caused by viscosity reduction due to heating is calculated by steady-state radial flow equations. The response of Sllccessive cycles of steam injection call also he calculated with this method.Excellent agreement is shown betweell calculated and actual field results. Also included are the results of several reservoir and process variable studies. The method is best suited for wells producing from a multiplicity of thin sands where the bulk of the stimulated production comes from the unheated reservoir. The flow equations used neglect gravity drainage and sall/ration changes within the heated region.

Steam injectivity during cyclic steam stimulation (CSS) at Cold Lake can be achieved only by injecting at pressures high enough to fail the formation mechanically. The reservoir also exhibits water/oil relative permeability hysteresis. This paper describes enhancements made to a thermal reservoir simulator to incorporate these Cold Lake physics. The geomechanical model allows both localized fracturing and global reservoir deformation (dilation and history-dependent recompaction). This representation allows the simulator to match injection and production pressures that are otherwise difficult to reproduce. The history-dependent relative permeability hysteresis model calculates gridblock relative permeabilities that always lie on or between input imbibition and drainage bounding curves. The model makes it possible to use laboratory-derived relative permeabilities in a simulation and still match field WOR's. A ----------------------~ ,,-- §

A history-matched, 2D, single-well numerical model was used to evaluate the contributions of four key drive mechanisms to early cyclic-steam-stimulation (CSS) oil recovery at Cold Lake, Alta. Formation compaction was found to be by far the dominant producing mechanism. Solution-gas drive was the most important of the remaining mechanisms. Fluid expansion had a relatively minor role. Gravity drainage accounted for little of the oil produced in the first two cycles, but increased in importance in subsequent cycles.

This paper was prepared for the 43rd Annual California Regional Meeting of the Society of Petroleum Engineers of AIME to be held in Bakersfield, Calif., Nov. 8–10, 1972. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copied. The abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor PETROLEUM ENGINEERS JOURNAL is usually granted upon requested to the Editor of the appropriate journal, provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers Office. Such discussions may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract This paper deals with the adequacy of scaling methods used for steam-flooding studies in laboratory models of reservoirs containing viscous oils. For highly viscous oils, it was found that accurate capillary pressure scaling is not required. For these oils the ratio of capillary to viscous forces is so low that unscaled capillary pressures have negligible effect on oil recovery behavior. However, in the case of medium-viscosity oils (less than 10,000 cp) unscaled capillary pressures result in prediction of optimistic oil recovery. A technique to bring capillary pressures into scale was investigated, but found to give only qualitative improvement. The technique caused predicted recovery behavior to be sensitive to predicted recovery behavior to be sensitive to flooding rates. Model predictions, after adjustment to field conditions to correct for differences between model and field starting oil saturations and injected steam quality, agree closely with numerical two-dimensional, three-phase calculations of the steam drive process. Oil recovery was found to depend mainly on the heat input per unit volume of reservoir sand. Injection rate was found to be a much less important variable. Introduction Laboratory models have been used for many years to simulate the behavior of a reservoir during thermal recovery operations. Unfortunately, the scaling of thermal recovery processes is difficult in small laboratory models because heat transfer and thermal effects on fluid properties must be accounted for as well as properties must be accounted for as well as capillary, gravity and viscous forces. To achieve complete scaling of capillary, gravity and viscous forces, fluids with properties analogous to those of reservoir fluids are properties analogous to those of reservoir fluids are required. To scale the variation of fluid properties with temperature (especially the properties with temperature (especially the viscosities), the actual crude oil-water system must often be used. Since the temperature dependency of viscosity is critical in thermal recovery models, scaling of capillary forces in these models has frequently been neglected in order to use actual reservoir fluids. Scaling theory of models has been discussed at length in the literature. Yet no quantitative information has been published indicating the scaling parameters having the greatest effect on results obtained with thermal models.