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Abstract Horizontal wells have been shown to be successful in improving oil recovery for marginal heavy oil reservoirs in Saskatchewan and Alberta. One commonly encountered problem in recovery operations for these unconsolidated reservoirs is the production of sand and fines. The settling and accumulation of the solid particles inside the horizontal wellbore represents a serious problem, with the horizontal well becoming partially plugged being a real possibility. This study investigates this problem, with focus on determining the roles played by different flow parameters on the settling and transport process. The physical model described in this work examines the transport process mechanistically. Conservation equations for the solid phase (sand particles) and the fluid phase (oil) are formulated, with the interaction between the phases described by empirical correlations. The oil is assumed to be a Newtonian fluid, and the sand particles are assumed to be spherical in shape and uniform in size. The system of equations is solved numerically to determine the distribution of sand particles and oil, and the respective pressure and velocity distributions as a result of the presence of a constriction inside the horizontal well. According to the simulation results, oil viscosity and particle size play important roles in the transport process, including controlling the gravitational settling tendency of solid particles inside the horizontal wellbore. The results provide insight into the mechanisms involved in the transport process; as such, they provide guidelines for production operations involving horizontal wells in unconsolidated and poorly consolidated reservoirs. Introduction One of the most common applications of horizontal well technology in Canada is to recover oil from heavy oil reservoirs in Saskatchewan and Alberta. In heavy oil reservoirs underlain with bottom-water, the use of horizontal wells has been found to improve primary recovery performance prior to water coning - recovering up to 15% of the initial oil in place (in shorter time, also), compared with only 5% for a vertical well. Horizontal wells have also been successfully used for increasing steamflood recovery. However, recovery operations in these heavy oil reservoirs are usually susceptible to sand production due to their unconsolidated nature. The produced sand could give rise to production problems. as the sand fill up the wellbore, prevent the operations of downhole pumps, etc. In the case of horizontal wells, sand production potentially poses an even more serious problem, due to the settlement and accumulation of sand particles at different positions along the well - leading to the reduction of the cross-sectional area of the wellbore open to flow (Figure 1). The ultimate effect of sand deposition could be the partitioning of the horizontal well into several segments, leading to a loss of production and a negation of the principal advantage of horizontal wells (large contact area with the reservoir). The study reported here investigates this problem. Specifically the study examines, through numerical simulation, the transport and distribution of sand particles, pressure, and velocity distributions in a horizontal well. A special feature of the physical model is the presence of a constriction inside the horizontal well. Solid-liquid flow encompasses many different areas of science and engineering, including the transport of colloids in rain water, sediment transport in river streams, slurry pipeline transportation, drill cuttings removal, transport of proppants in hydraulically fractured wells, etc. The large number of independent variables involved in these transport processes, coupled with the complex interaction between the variables have precluded comprehensive analytical studies of these processes mechanistically. Instead, many experimental studies have been carried out over the years. P. 471^

Abstract Canada's heavy oil and oil sands deposits are estimated to contain as much oil as the conventional oil resources of the entire world. Heavy oil deposits, in particular those in southwestern Saskatchewan and southeastern Alberta, represent an attractive target for exploitation as the in-place heavy oils are mobile under reservoir conditions. These reservoirs typically have good porosity, high permeability (1–5 darcies), high initial oil saturation >65%), and the oil viscosity ranges from 1000 to 1500 cp; but the pay thickness is between 3–10 metres and often underlain by bottom water zone ("bottom water"). Primary recovery in these reservoirs typically amounts to less than 5% of the initial oil in place (IOIP). In a few cases, where the conditions are more favorable, use of horizontal wells has increased primary recovery to 15-20% prior to water coning. This still leaves up to 80% of the oil in place unrecovered. Using a scaled physical model of the Aberfeldy reservoir (Saskatchewan), steamflood experiments were performed to investigate steamflood recovery performance using horizontal injection and production wells. This paper reports results of analyses made for two types of experiments; one was for steamflooding a homogeneous reservoir (base case run), and the other was for steamflooding a reservoir having a 20% net pay bottom water layer. Analyses include comparisons between steam zone volumes obtained experimentally and theoretically, and heat distribution (heat injected, heat loss, heat accumulated, and heat produced) during a steamflood The scale up of laboratory results to predict prototype field performance is also presented. The analytical heat loss model, based on the simultaneous solution of two heat conduction equations, showed a 3.1% difference from experimental results. Scaled-up experimental data, for the base case run (horizontal injector and producer), showed that approximately 20% of the initial oil in place (IOIP) was recovered after 0.8 PV of steam (CWE) had been injected. For a reservoir having a 20% net pay bottom water, after 0.8 PV of steam (CWE) had been injected, heat accumulated in the formation was found to be approximately 3776.6 kJ. Of this, 2000 kJ of energy was stored in the matrix, and the fluids in the reservoir contained 1776.6 kJ of energy. The increase in the oil recovery for a reservoir having 20% net-pay bottom water layer depends on how the energy contained in the fluids is managed Introduction Over 20 billion barrels of oil are contained in the marginal heavy oil reservoirs of Saskatchewan and Alberta. These reservoirs are thin (3–10 meters of pay) and often in communication with an underlying water zone. Cyclic steam stimulation and steamflooding operations using vertical wells have proven uneconomic in these reservoirs, mainly due to excessive channeling of steam. On the other hand, horizontal wells have been shown to be capable of improving steamflood recovery performance, due to their extended contact with the reservoir and their ability to improve sweep efficiency (due to a delay in steam override, and minimizing effect of heat loss to the cap/base rock). This study attempts to provide insight into the performance prediction of steamflooding a marginal heavy oil reservoir using horizontal injection and production wells, and looks at different steamflooding strategies for improving recovery. These objectives were achieved experimentally using a scaled physical model, and a visual unscaled model. P. 93^