Predictive Theory for Viscous Fingering in Compositional Displacement

Blunt, Martin J.; Barker, J.W.; Rubin, Barry; Mansfield, Mark; Culverwell, I. D.; Christie,

doi:10.2118/24129-pa

Cited by 51 publications

(22 citation statements)

References 28 publications

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“…However, in many cases of practical interest, particularly CO 2 sequestration, the mobility ratios are small leading to Saffman-Taylor instabilities [Saffman and Taylor, 1958;Blunt et al, 1994], which can enhance spreading even further. Using the measures for spreading developed herein, we studied the dispersion of a saturation front in such unstable scenarios.…”

Section: Discussionmentioning

confidence: 99%

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Effective two‐phase flow in heterogeneous media under temporal pressure fluctuations

Bolster

Dentz

Carrera

2009

Water Resources Research

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[1] We study the combined effect of spatial heterogeneity and temporal pressure fluctuations on the dispersion of the saturation of a displacing fluid during injection into an immiscible one. In a stochastic modeling framework, we define two different dispersion quantities, one which measures the front uncertainty due to temporal pressure fluctuations and another one which quantifies the actual spreading and dispersion of the saturation front in a typical medium realization. We derive an effective large-scale flow equation for the saturation of the displacing fluid that is characterized by a nonlocal dispersive flux term. From the latter we derive measures for the spread of the saturation front due to spatiotemporal fluctuations. Our analysis demonstrates that temporal fluctuations enhance the front uncertainty but not the average spreading of the saturation front. The analytical developments are complemented by numerical simulations of the full two-phase flow problem. Correct assessment of the spread of the saturation front is of importance to several applications, including the assessment of the sequestration potential of a carbon dioxide storage site, for example. Spreading enhances the surface area between the fluids, which in turn enhances the dissolution and entrapment efficiency. The latter facilitates reactions and thus the sequestration of CO 2 in stable forms. Our study provides a theoretical basis for the design of injection strategies to optimize dispersion and to minimize uncertainty of the saturation front.

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Section: Discussionmentioning

confidence: 99%

“…[49] The last three cases we consider, namely, i, k and l, are for a viscosity ratio M = 0.2, which is known to be affected by the Saffman Taylor instability [Marle, 1981;Blunt et al, 1994]. It is also known that heterogeneity can have a stabilizing or destabilizing effect depending on boundary conditions and the mobility ratio [Tartakovsky et al, 2003].…”

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confidence: 99%

Effective two‐phase flow in heterogeneous media under temporal pressure fluctuations

Bolster

Dentz

Carrera

2009

Water Resources Research

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“…In Eq. 6, F(C ch ) is the solvent fractional flow (in this case, it is CO 2 ), which can be obtained from the ToddLongstaff model for miscible viscous fingering [3,42].…”

Section: Model Descriptionmentioning

confidence: 99%

A three-phase four-component streamline-based simulator to study carbon dioxide storage

2009

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We have extended an existing streamline simulator (Batycky et al., SPE Reserv Eng 12(4):246-254, 1997) that considered two phases (aqueous and hydrocarbon) and two components (water and oil) to handle three-phase (aqueous, hydrocarbon, and solid), fourcomponent (water, oil, CO 2 , and salt) transport applied to CO 2 injection. We solved CO 2 transport equations in the hydrocarbon and aqueous phases along streamlines and in the direction of gravity. To capture the physics of CO 2 transport, in the hydrocarbon phase, we used the Todd-Longstaff model (Todd and Longstaff, J Pet Technol 24 (7): [874][875][876][877][878][879][880][881][882] 1972) to represent subgridblock viscous fingering. We implemented a thermodynamic model of mutual dissolution between CO 2 and water with salt precipitation (Spycher et al., Geochim Cosmochim Acta 67 (16): [3015][3016][3017][3018][3019][3020][3021][3022][3023][3024][3025][3026][3027][3028][3029][3030][3031] 2003; Spycher and Pruess, Geochim Cosmochim Acta 69 (13): [3309][3310][3311][3312][3313][3314][3315][3316][3317][3318][3319][3320] 2005). The resultant changes in porosity and permeability due to chemical reaction and salt precipitation were also considered. We accounted for two cycles of relative permeability hysteresis (primary and secondary drainage and imbibition) by applying two different trapping models: Land (SPE J 8:149-156, 1968) and Spiteri et al. (SPE J 13(3):277-288, 2008).Relative permeability changes and variations in the trapped nonwetting phase saturations due to hysteresis were updated on a block-by-block basis. We verified our simulator by comparing one-dimensional simulation results with analytical solutions. We then performed simulations on three-dimensional reservoir models. We first simulated dry CO 2 injection in an aquifer to investigate the effect of salt precipitation. After 2 years of CO 2 injection, the permeability reduced by approximately 20%. We then used the simulator to design CO 2 injection strategies in aquifers to maximize CO 2 storage and in oil reservoirs to optimize both CO 2 storage and oil recovery. Simulations were conducted on a North Sea reservoir description. We propose to inject CO 2 and water simultaneously, followed by chase brine injection, which could render the majority of CO 2 injected immobile while giving a much higher storage efficiency than injecting CO 2 alone.

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“…It can also help stabilize displacements for which the oil-water shock front mobility ratio is greater than 1 [5], thus reducing or preventing the degree of viscous fingering. An example of this is shown in Fig.…”

Section: Introductionmentioning

confidence: 99%

Analytical solution of polymer slug injection with viscous fingering

Hamid

Muggeridge

2018

Comput Geosci

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We present an analytical solution to estimate the minimum polymer slug size needed to ensure that viscous fingering of chase water does not cause its breakdown during secondary oil recovery. Polymer flooding is typically used to improve oil recovery from more viscous oil reservoirs. The polymer is injected as a slug followed by chase water to reduce costs; however, the water is less viscous than the oil. This can result in miscible viscous fingering of the water into the polymer, breaking down the slug and reducing recovery. The solution assumes that the average effect of fingering can be represented by the empirical Todd and Longstaff model. The analytical calculation of minimum slug size is compared against numerical solutions using the Todd and Longstaff model as well as high resolution first contact miscible simulation of the fingering. The ability to rapidly determine the minimum polymer slug size is potentially very useful during enhanced oil recovery (EOR) screening studies.

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Predictive Theory for Viscous Fingering in Compositional Displacement

Cited by 51 publications

References 28 publications

Effective two‐phase flow in heterogeneous media under temporal pressure fluctuations

Effective two‐phase flow in heterogeneous media under temporal pressure fluctuations

A three-phase four-component streamline-based simulator to study carbon dioxide storage

Analytical solution of polymer slug injection with viscous fingering

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