Analysis of Scaled Steamflood Experiments

Abstract

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^