This paper presents the results of a comprehensive study to improve our understanding of high-mobility-ratio waterfloods (HMRWFs) and to improve performance prediction. Published data on heavy-oil water-injection field projects are limited. Several successful HMRWF projects have been reported, and they show significant oil recovery at high water cut. However, the range of reported recovery is large-waterflood (WF) recoveries of approximately 1-or-2% to 20% of original oil in place (OOIP) have been reported for similar reservoirs. Higher viscosities result in lower recovery.Mechanistic studies using fine-scale simulations show that the viscosity (or mobility) ratio primarily controls oil-recovery response, and that the recovery is lower at higher viscosity ratios. Further, viscous fingers dominate high-viscosity-ratio floods, and mobile water can reduce recovery significantly. Field-scale simulation results indicate that heterogeneity plays a more important role for an HMRWF than for conventional waterfloods. The amount of primary production before the start of the waterflood has a larger effect on incremental oil recovery for high-mobilityratio floods. Furthermore, highly correlated thin, thief zones reduce recovery of HMRWFs more severely, and rock wettability (relative permeabilties) strongly influences oil recovery. These results indicate that, in addition to reservoir geology, accurate viscosity and relative permeability measurements are essential for a reliable performance prediction. Field DataPublished and other available data were reviewed critically to ascertain field performance of heavy-oil projects under water injection. Although several published papers discuss heavy-oil field projects, only a few include actual production data (Oefelein and
This paper presents results of a comprehensive study to improve our understanding of High Mobility Ratio Water Flood (HMRWF) and to improve its performance prediction.Published data on heavy oil water injection field projects are limited.Several successful HMRWF projects have been reported, and they show significant oil recovery at high water cut.However, the range of reported recovery is large - waterflood recoveries of ~ 1–2% to 20% OOIP have been reported for similar reservoirs.Higher viscosities result in lower recovery Mechanistic study using fine-scale simulations show that viscosity (or mobility) ratio primarily controls oil recovery response, and that the recovery is lower at higher viscosity ratios.Further, viscous fingers dominate high viscosity ratio floods, and mobile water can significantly reduce recovery.Field-scale simulation results indicate that heterogeneity plays a more important role for a HMRWF (than conventional waterfloods).The amount of primary production prior to the start of the waterflood has a larger effect on incremental oil recovery for high mobility ratio floods.Further, highly-correlated, thin, thief zones reduce recovery of HMRWF more severely, and rock wettability (relative permeabilties) strongly influences oil recovery.These results indicate that accurate viscosity and relative permeability measurements are essential for a reliable performance prediction. Introduction Waterflood has been conducted in many high viscosity reservoirs in the past, and several water injection projects in high viscosity reservoirs are currently ongoing and planned around the world.1–18However, published data on High Mobility Ratio Water Flood (HMRWF) performance is limited and the results are sometimes conflicting.Further, it has been postulated that some of the recovery mechanisms might be different.20 It is apparent from the literature that our understanding of HMRWF performance is inadequate. This paper presents results of a comprehensive study to provide improved insight into mechanisms governing HMRWF and to help improve performance prediction.The specific objectives were to:evaluate published field data,determine key parameters that govern the process using analytical methods and fine-scale mechanistic numerical models, andquantify effects of reservoir heterogeneity on HMRWF field performance.Accordingly, the paper is divided into four parts.The first presents a review of published field data.Next, definitions of mobility ratio are examined and a preferred definition is proposed.This is followed by a fine-scaled mechanistic modeling of HMRWF to identify key parameters.Finally, field-scale simulations are conducted to delineate key differences between HMRWF and conventional water flood. Results of this study can be used to improve forecast and interpretation of HMRWF field performance.Furthermore, the paper identifies key parameters that govern process performance, which should result in improved project design. Field Data Published and other available data were reviewed critically to ascertain field performance of heavy oil projects under water injection.Although several1–20 published papers discuss heavy oil field projects, only a few (Refs. 1, 3–5, 7, 8, 12, 13, and 18) have some production information.Furthermore, only two of the published papers (Refs.1 and 3) have sufficient details on actual performance.The published data are from Western Canada, California, and other parts of the world. They include offshore and onshore fields, both thick and thin reservoirs, horizontal and vertical wells, and a variety of viscosity ratio.However, a majority are from Saskatchewan, Canada, where water injection was initiated in the 1970's-80's, and employ vertical wells.
Near-well effects can have a strong impact on reservoir flow. Current reservoir modeling practice often uses coarse-scale flow simulation models, which may lead to biased results, compared with fine-scale models. In this work, we extend and apply a recently developed near-well multiphase flow upscaling technique to the coarse-scale simulation of heavy-oil primary production. For heavy oils, oil viscosity is a strong function of pressure when the pressure is below the bubble point. Therefore, the upscaled mobility functions (from near-well multiphase upscaling) depend on both pressure and saturation, which cannot be directly input to general purpose reservoir simulators. This is very different than the upscaled mobility functions for typical black-oil fluids, in which oil viscosity does not vary significantly with pressure. Accordingly, the upscaled mobility functions are often equivalent to upscaled relative permeabilities (as functions of saturation only). In this work, we develop two procedures to derive either the upscaled relative permeability or viscosity functions from the phase mobility functions, thus decoupling the dependency on pressure and saturation. It is found that the upscaled oil viscosity provides more accurate predictions than the upscaled relative permeabilities, especially at early time. This is because that the rapid change of pressure at early stage is captured sufficiently in the upscaled oil viscosity (as a function of pressure). The use of upscaled viscosity function in multiphase upscaling is new, and has not been presented in previous studies. We also introduce a grouping technique to reduce the number of upscaled flow functions in coarse-scale models. This is based on an observation that there is a strong correlation between the upscaled flow functions and the coarse-scale well-block permeabilities. The proposed methods are applied to realistic models from heavy-oil fields. For cases considered, the nearwell multiphase flow upscaling considerably improves upon the standard coarse models. The use of upscaled relative permeability and viscosity functions, as well as the grouping of upscaled flow functions, provides practical applicability for fast and accurate forecast using coarse-scale models.
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