Optimal Voidage Replacement Ratio for Communicating Heavy Oil Waterflood Wells

Vittoratos, E.; Coates, R.; West, Chris C.

doi:10.2118/150576-ms

Cited by 17 publications

(4 citation statements)

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“…However, it has been proposed that this concept might not be valid for waterfloods in heavy oil reservoirs where VRR<1 could be beneficial. The potential advantages of this strategy (VRR < 1) to improve oil recovery in heavy oil waterfloods is due to the activation of one or more of the following mechanisms: solution gas drive, foamy oil drive, in-situ emulsification and three-phase relative permeability (Brice, Ning, Wood & Renouf, 2014;Delgado, Vittoratos & Kovscek, 2013;San Blas and Vittoratos, 2014;Vittoratos and Boccardo, 2015;Vittoratos, Coates & West, 2011;Vittoratos, Zhu & West, 2014). The proposed approach of optimum VRR for waterfloods in heavy oil reservoirs can impact polymer floods performance and should be considered when evaluating the technical and economic feasibility of polymer flooding in viscous oil reservoirs.…”

Section: Polymer Injection Ratesmentioning

confidence: 99%

Historical and recent observations in polymer floods: An update review

Manrique¹,

Ahmadi²,

Samani³

2017

CT&F Cienc. Tecnol. Futuro

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Polymer flooding has been the most widely used chemical enhanced oil recovery (EOR) method. The experience gained over the past decades from laboratory studies to project design and field implementation has been well documented in the literature. The main objectives of this paper are to evaluate recent observations of polymer floods that report injection rates leading to pressure values above the formation fracture pressure (FFP), high polymer production, formation of tight emulsions and/or productivity losses.Based on this review, it can be concluded that no direct evidence exists to support that injecting polymer above the FFP will lead to more polymer production. However, uncertainties associated with the estimation of fracture propagation/dimensions using pressure Fall-Off Tests (FOT) still remain. High polymer production, other than severe channeling, is generally reported in large scale/commercial projects. The impact of oil geochemistry/ composition and water salinity on oil-water-polymer emulsions is commonly overlooked in polymer flood studies. The formation of in-situ emulsions can also explain the injectivity and/or productivity reduction and well test interpretation (i.e. FOT) reported in polymer floods. It was also identified that the OPEX (Operational Expenditures) associated with oil-water separation in the presence of polymer and productivity losses (i.e. workovers, stimulation costs) are generally underestimated. Finally, this review is expected to contribute with the planning, design and implementation of future polymer flood pilots and field expansions. OBSERVACIONES HISTÓRICAS Y RECIENTES EN INYECCIÓN DEPOLÍMEROS: REVISIÓN ACTUALIZADA. OBSERVAÇÕES HISTÓRICAS E RECENTES DE INJEÇÃO DE POLÍMEROS:REVISÃO ACTUALIZADA. EDUARDO MANRIQUE et. al. 18 L a inyección de polímeros es el método químico de recobro mejorado con mayor número de implementaciones a escala de campo. La experiencia adquirida en las últimas décadas desde estudios de laboratorio hasta el diseño e implementación de campo ha sido bien documentada en la literatura. El objetivo principal de este trabajo es evaluar observaciones recientes de proyectos de inyección de polímero reportando tasas de inyección por encima de la presión de fractura de la formación, alta producción de polímero, formación de emulsiones viscosas y/o pérdidas de productividad.Basados en esta revisión, se puede concluir de que no existen evidencias directas de que la inyección de polímero a tasas que impliquen superar la presión de fractura induzcan a una mayor producción de polímeros. Sin embargo, existen incertidumbres relacionadas con la estimación de las dimensiones y propagación de fracturas utilizando pruebas de caídas de presión (FOT). La alta producción de polímero, por razones diferentes a canalizaciones severas, generalmente se reportan en proyectos a escala comercial. Por otra parte, el impacto de la composición y geoquímica del crudo y de la salinidad del agua en la formación de emulsiones agua:petróleo:polímero ha sido subestimado en estudios de in...

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Section: Polymer Injection Ratesmentioning

confidence: 99%

Historical and recent observations in polymer floods: An update review

Manrique¹,

Ahmadi²,

Samani³

2017

CT&F Cienc. Tecnol. Futuro

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“…A large 'big can' was specially designed to permit the formation of a reproducible flow path (see Fig. 3, Vittoratos et al, 2011). Experiments were performed with an 18.6 and a 12.5 °API oil .…”

Section: Laboratory Vrr Experimentsmentioning

confidence: 99%

“…VRR < 1 activates many recovery mechanisms (Vittoratos et al, 2011). Some mechanisms can be enumerated and examined and others may exist that are yet to be identified.…”

Section: Analytical and Numerical Vrr Simulationsmentioning

confidence: 99%

Doctrines and Realities in Reservoir Engineering

Vittoratos¹,

Kovscek

2017

SPE Western Regional Meeting

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Doctrines often develop with minimal empirical support. This observation is clear in reservoir engineering for heavy and viscous oils. Our objective is to develop a deeper appreciation of the empirical realities to permit improvement of depletion plans and thereby enable projects that are deemed uneconomic by the application of the misleading doctrines. Accordingly, this paper reviews the evidence for and against three doctrines in current use to develop depletion plans: (i) optimal recovery is obtained using a voidage replacement ratio (VRR) of 1, (ii) the Buckley-Leverett formulation applies uniformly to heavier oils, and (iii) viscous fingering dominates unstable multiphase flows.Of primary importance is the doctrine that optimal waterflood response is obtained for a VRR of 1 both on an instantaneous and cumulative basis. A VRR of 1 is mandated in some regulatory jurisdictions and accepted unconditionally by many large oil companies. In the last decade, however, empirical, laboratory, and simulation investigations have demonstrated that, particularly for heavier oils, periods of VRR < 1 significantly increase the oil recovery and reduce water production. Optimal voidage management increases oil recovery by an amount similar to a variety of EOR techniques at minimal cost.A second doctrine is that the multiphase flows within the reservoir occur via the slipping of phases past each other, as formalized by the Buckley-Leverett formulation. Again, empirical and laboratory evidence demonstrates that in many cases two-phase flow occurs by emulsification of one phase, e.g., injected water disperses as small micron size droplets within a continuous oil phase. Such emulsion flows yield results that contradict current doctrines; e.g., decline curves are not monotonic but have steps associated with the type of emulsion. Likewise, the efficacy of polymer flooding is independent of polymer concentration after it exceeds the minimum value needed to support emulsification of water into the oil. These novel predictions have considerable commercial value.Finally, viscous fingering is often attributed to the instability of flow when the displacing phase (water) has a viscosity smaller than that of the displaced phase (oil). Though elegant mathematical formulations explain such unstable flows under idealized laboratory conditions, the reality is that slow pressure diffusion within heavy oils is the originating factor in channelized reservoir flows because commercial injection rates cause altered porosity distributions that initiate the preferential path flow.The appreciation of the empirical realities permits improvement of commercial depletion planning and enables a greater number of projects. These concepts are applicable in almost all heavy-oil reservoirs; they 2 SPE-185633-MS may also be applicable for lighter oils that possess oil chemistry that is typical of heavier oils, e.g., high acid content.

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“…In these experiments, a very reproducible communication path was created in a five foot long 'big can' and various VRR strategies were tested after the commencement of water production from the production end of the can. The procedures and results have been released in some detail for an 18 API Alaska North Slope oil (Vittoratos et al, 2011). The reproducibility of the communication path is remarkable, and the large pore volume of the big can permit excellent mass balances of all three phases including the gas.…”

Section: Laboratory Waterflood Observations With Vrr <mentioning

confidence: 99%

VRR < 1 Is Optimal for Heavy Oil Waterfloods

Vittoratos

West²

2013

SPE Offshore Europe Oil and Gas Conference and Exhibition

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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.

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Optimal Voidage Replacement Ratio for Communicating Heavy Oil Waterflood Wells

Cited by 17 publications

References 3 publications

Historical and recent observations in polymer floods: An update review

Historical and recent observations in polymer floods: An update review

Doctrines and Realities in Reservoir Engineering

VRR < 1 Is Optimal for Heavy Oil Waterfloods

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Optimal Voidage Replacement Ratio for Communicating Heavy Oil Waterflood Wells

Cited by 17 publications

References 3 publications

Historical and recent observations in polymer floods: An update review

Historical and recent observations in polymer floods: An update review

Doctrines and Realities in Reservoir Engineering

VRR &lt; 1 Is Optimal for Heavy Oil Waterfloods

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VRR < 1 Is Optimal for Heavy Oil Waterfloods