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).
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.
Increasingly, the reservoirs remaining to be developed have lower gravity, particularly for the older offshore basins such as the North Sea. Optimal waterflood VRR management will be the key to their economic success. Current industry paradigms and regulatory mandates assume that the light oil practice of complete voidage replacement, VRR = 1, should be continued for the heavy oil reservoirs to be waterflooded. Empirical data, laboratory experiments, and mathematical simulation methods indicate, however, that for heavy oil waterfloods the optimal voidage replacement ratio (VRR) is less than one. Analysis of empirical data from an Alaskan heavy oil reservoir (18 API) show that after water breakthrough, periods of VRR < 1 are important for increased recovery. Laboratory data from an Alaskan heavy oil (12 API) waterflooded in a five foot long 'big can' show significantly higher recoveries with VRR < 1. Numerical simulations are directionally in agreement with these empirical & laboratory observations even when only using conventional concepts.Many more recovery mechanisms are activated with VRR < 1 than with VRR = 1. Some are readily understood with existing conventional concepts. Common geological depositional environments do not permit complete waterflood sweep, and 'cul de sacs' of unswept oil are left behind that can only be depleted with the activation of solution gas drive by VRR < 1. Less conventional concepts include the chemical changes that accompany pressure declines, that result in more surface activity and increased in-situ emulsion multiphase flow, which may self-divert to increase waterflood conformance. The numerical simulation of the VRR < 1 process is difficult and only a limited number of the mechanisms can be effectively modeled. Nonetheless, directional trends have been identified.
Empirical data, laboratory experiments, and mathematical simulation methods indicate that for many heavy oil waterfloods the optimal voidage replacement ratio (VRR) is less than one. Many more recovery mechanisms are activated with VRR<1 than with VRR = 1. Some are readily understood with existing conventional reservoir engineering concepts, while others invoke emulsion & foamy oil multiphase flows that are activated under changing reservoir conditions. Not all the consequences of VRR<1 are positive for recovery. In aggregate, however, as displayed in empirical observations, VRR<1 can result in a significant increase in reservoir oil recovery, particularly for the heavier oils. This paper focuses on the quantification of the relative importance of the mechanisms activated by VRR<1 in saturated or nearly saturated reservoirs. The absolute value of the VRR<1 depends primarily on the oil quality and its associated properties, whereas the optimal time evolution of the VRR depends on the well spacing and the reservoir heterogeneity of the depositional environment. Numerical simulations have ranged from simple 1D models to a detailed fluvial depositional environment model. The role of relative permeabilities are demonstrated by the 1D model. The 3D field models of increasing geological complexity are useful for quantifying the incomplete waterflood sweep, and the role of VRR < 1 in activating solution gas drive to deplete the ‘cul-de-sacs’ of bypassed oil. We also propose here a numerical model to incorporate emulsion flow behavior into heavy oil water flooding, calibrated using data from a large scale (‘big can’) experimental waterflooding study of a heavy oil prone to emulsion formation. The methodologies developed in this study show that for heterogeneous heavy oil reservoirs the incremental recovery expected from an optimized VRR < 1 process is similar to that of other commercial IOR processes such as polymer flooding, but with very little incremental cost.
The geological aspects of drilling horizontal wells in various geologic environments worldwide are reviewed. Predominantly development wells, they are often drilled in locations where a conventional well would not achieve the same geological and subsequently economic, objectives. This paper summarizes recent activity and demonstrates that geologic conditions play a large part in determining the success or failure of a horizontal drilling project. The examples cited in this paper are all taken from previously published literature and include horizontal drilling projects in the USA, United Kingdom, Norway, Italy, The Netherlands and Denmark. This paper concludes that a large range of geological conditions have been tested by horizontal drilling with varying degrees of success, the results of which might prove helpful in assessing future prospects for horizontal wells.
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