Current paradigms and regulatory mandates implicitly assume that waterflood reservoir management practices successful in light oils can be extended unmodified to heavier oils. In particular, complete voidage replacement is considered optimal irrespective of oil chemistry; furthermore, it is assumed that the Buckley-Leverett multi-phase flow formulation, successful in light oils, is equally applicable with heavier crudes. Surprisingly, despite the paramount importance of these concepts to successful reservoir management, there is little public domain documentation on any empirical tests of these assumptions using field data. We here report that our ongoing empirical examination has accumulated observations that suggest that optimal heavy oil waterflood management may differ from that of light oils. The literature has anecdotal accounts of the difficulty of maximizing oil recovery for heavy oil reservoirs while attempting to achieve complete voidage replacement. In the North Slope of Alaska, efforts to maximize oil production early in the waterflooding of isolated hydraulic blocks have led to a VRR < 1. For heavy oils, we have previously identified a flow regime with WOR ∼ 1 for extended periods of time prevalent for reservoirs worldwide. In Alaska, where we possess detailed fluid, well and reservoir information, we have correlated this regime with hydraulic units with incomplete voidage replacement. The WOR ∼ 1 flow regime can be interpreted as a water-in-oil emulsion flow which is intrinsic to the water/oil system chemistry and not to the details of the reservoir stratification, explaining its widespread prevalence. Laboratory heavy oil waterfloods with a VRR = 0.7 recover more oil than those with VRR = 1, and provide evidence of in-situ water-in-oil emulsion formation. Furthermore, the laboratory floods suggest that the recovery prize for optimal voidage strategy may be estimated by a simple heuristic equation: optimal recovery process (VRRopt) ∼ recovery pure waterflood (VRR = 1) + recovery pure solution gas drive (VRR = 0).

From the analyses of production data from thousands of cyclic steam stimulation (CSS) cycles at Cold Lake, a conceptual model of theflow regimes has been developed It indicates that the tradi-tional reservoirflow conceptualization of bitumen and water slip-ping past each other according to the relative permeability curves is, to a large extent, inapplicable at Cold Lake, and very likely inappropriate to visualizing steam stimulation in general.Upon completion of steam injection, three distinct and sequential flow regimes characterize the production phase. type I, free water with little if any bitumen production; type II, slugs offree water alternating with slugs of water in bitumen emulsion, resufting i'n scattered production rates; and type III, a single phase flow con-dition compi&ng of water in bitumen emulsion with very smooth, slowly varying production rates. In early cycles the majority of the bitumen production occurs during type IIIflow, with the type ii regime being small. Over time, as the cycle number increases, the water content of the emulsion in type IlIflow reaches a max-imum of about 50%; the flow then increasingly remains in type Il condition, corresponding to a decline in the well's OSR and increase in the waterloil ratio (WOR) as the well begins to ap-proach its economic limit. T7te swelling of the bitumen by the en-trained waterpermits the emulsion to occupy essentially the whole pore space during type IIIflow, incorporating an otherwise con-tinuousfree water that could competefor production at the well-bore. This may be the physical reason for the need to introduce hysteresis to depress the water relative permeability during numer-ical stimulations of the production phase of CSS. Introduction Using cyclic steam stimulation (CSS), Esso Resources Canada Limited produces in excess of 14 000 m3/day of 10 API gravity bitumem from the Clearwater formation at Cold Lake, Alberta(l).A significant technological effort supports this large commercial thermal recovery project. Progress has been made in delineating the relative importance of key recovery mechanisms of CSS, such as formation recompaction, solution gas drive and gravity drainage(2). This paper reports the reservoir flow regimes during the production phase of CSS deduced from the mwyses of produc-tion data from thousands of cycles. This analysis leads to the view-point that the traditional reservoir flow conceptuamtion of bitumen and water slipping past each other according to the rela-Keywords: Cyclic steam stimulation, Flow regimes, Emulsion, Relative permeability, Cold Lake. Paper reviewed and accepted for publication by the Editorial 82 tive permeability curves is, to a large extent, inapplicable at Cold Lake, and very likely inappropriate to visualizing steam stimula-tion in general.Perusal of the production data shows that the water and bitu-men production rates often track each other with considerable co-herence; this is most striking when the WOR is one. This is _ illustrated in Figure 1 for well A in its fourth cycle production. Note...

Summary Cyclic steam stimulation (CSS) typically is thought of as a single-well process. At Cold Lake, however, where steam injectivity is achieved by fracturing the formation, considerable interwell communication is observed. The result is usually the watering out of a producer by condensed steam from a neighboring injector. These interwell interactions greatly complicate sam-injection scheduling for commercial projects involving hundreds of wells but do not seem to reduce bitumen production in early cycles. Field experience indicates that steaming rows of wells sequentially with 50% overlap in injection time between adjacent rows significantly reduces water transfer between wells, increases the conformance of the injected heat, and reduces the field's tendency to form communicating well couplets. Exploratory numerical simulations show that the impact of steaming strategy on bitumen production is not significant until later cycles. Introduction CSS is a complex recovery process composed of a variety of recovery mechanisms whose relative importance changes with cycle number. For the Cold Lake reservoir, where steam injectivity is achieved by fracturing the formation, modeling the process is particularly challenging. The basis for investment decisions for commercial expansion, therefore, has been largely empirical. Even so, efforts to understand the process, and in particular to delineate the recovery mechanisms, are continuing. CSS generally has been modeled as a single-well process. The injected heat and fluids are envisioned to remain in the vicinity of the wellbore, lowering bitumen viscosity and increasing reservoir pressure. During the production phase, the increased reservoir pressure, along with gravity, drives heated bitumen to the wellbore. No-flow boundary conditions are assumed to encircle the spacing area of the well. Conceptually, such a model is correct for small steam-stimulation volumes. As the steam-stimulation volumes increase, however, the disturbances associated with heat injection become less localized; for very large volumes associated with continuous injection, the process evolves into a multiwell steamflood process. Thus, a continuum exists from single-well CSS to multi-well displacement. At the Leming pilot at Cold Lake, substantial single-well CSS behavior has been observed and successfully modeled for well patterns with large aspect ratios. CSS is not a single-well process. however, for commercial projects with steam-stimulation volumes of 8000 m3 [50,000 bbl] or more and wells on ha [4-acre] spacing with aspect ratios of 1.7 For example, a fraction of the fluids injected in a well may not be produced by the same well but rather by neighboring wells on production, indicating that elements of displacement also exist in the process. Interwell interactions during CSS at the Cold Lake area have been reported. This interwell interference or "communication" affects the production profiles dramatically. Thus, the total performance of the reservoir is not merely the summation of isolated wells whose performance is independent of the steaming sequence. This paper gives examples of the interwell communication observed with CSS at Cold Lake and introduces terminology useful for quantifying the process. Approaches to inferring the properties of the interwell communication path from surface measurements are outlined, and the practical limitations in their use noted. The paper then discusses a steaming strategy to reduce the degree of fluid breakthrough and to increase the reservoir conformance of the injected heat. Finally, results from numerical simulations of the multiwell CSS process are presented and compared with field experience.

Steam stimulation of the Cold Lake bitumen reservoir causes fracturing of the formation. Steam enters via convection along the fracture plane, and heat propagates perpendicular to this plane by conduction, which in some cases may be enhanced by convection. Temperature profiles from observation wells located around stimulated wells directly give the energy distribution at those locations. The analysis can be extended beyond energy distribution by distinguishing regions of convective and conductive heat transfer in the temperature profiles. Simple analytical models can then yield important insights into the cyclic steam stimulation process, such as fracture geometry and fluid flow velocity. Eight field cases are discussed representing profiles from the injection, shut-in, and production phases of the process.

Accumulated field empirical observations suggest that water injected to displace heavy oils forms in the reservoir channel-like communication paths from the injectors to the producers. The evidence comes from mass balances and, more recently, from 4D seismic monitoring of heavy oil waterfloods. The reasons for this are multifold, including unconsolidated sand formation dilation about injectors due to slow pressure diffusion in heavy oils, reservoir heterogeneities in permeability and saturation, sand production from the reservoir, and the instability of the displacement interface due to the high mobility ratio between water and heavy oil. Once formed, the channels can degrade further economic recovery of the heavy oil as the water oil ratios increase significantly. This study reports on initial results from a laboratory program to test the optimal reservoir management response upon formation of such communication paths in heavy oil waterfloods.To physically simulate reservoir waterflood behavior under the existence of a communication path, a large scale 'big can', five feet long with a ten inch by ten inch cross section, was designed and constructed that allowed for the creation of a highly reproducible communication path from the injection to production end of the can. This was a mandatory requirement for accurate comparison between alternative reservoir management strategies whose differences would otherwise be hidden by variations in random communication path formation. The design has proven to be highly successful. Our first objective was to test whether the industry paradigm and the regulatory mandated practice of maintaining a voidage replacement ratio (VRR) of one throughout the entire waterflood is optimal. Live 18.6 API Alaska North slope oil was used to saturate four Darcy sand that filled the big can. Upon creation of the communication path, three VRRs were tested: 1.0 (conventional waterflood), 0.7 (hybrid waterflood/solution gas drive), and 0.0 (conventional solution gas drive). The VRR=0.7 run outperformed the conventional VRR=1.0, suggesting that periods of under injection may improve heavy oil waterflood response upon formation of injector-producer communication.