Slow migration of mobilised fines during flow in reservoir rocks: Laboratory study

Oliveira, Maira A.; Vaz, Alexandre; Siqueira, F. D.; Yang, Yumeng; You, Zhenjiang; Bedrikovetsky, Pavel

doi:10.1016/j.petrol.2014.08.019

Cited by 98 publications

(33 citation statements)

References 39 publications

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“…(1) are equal to hðr e min Þ ¼ 41:3 lm and hðr e min Þ ¼ 49:7 lm for cores B-1 and B-2, respectively. According to a ''golden rule of filtration'' [17,18] the particle jamming ratio 2rs h À Á…”

Section: Optimal Particle Placementmentioning

confidence: 99%

Stimulation of coal seam permeability by micro-sized graded proppant placement using selective fluid properties

Keshavarz

Badalyan

Carageorgos

et al. 2015

Fuel

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Section: Optimal Particle Placementmentioning

confidence: 99%

Stimulation of coal seam permeability by micro-sized graded proppant placement using selective fluid properties

Keshavarz

Badalyan

Carageorgos

et al. 2015

Fuel

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“…Laboratory flow-through tests on natural reservoir cores with varying piecewise constant flow velocities and water salinities show that the core permeability stabilizes significantly later than the moment corresponding to when one pore volume has been injected [Ochi and Vernoux, 1998;Oliveira et al, 2014]. This delayed-stabilization effect is attributed to the slow particle drift near pore walls and to particle sliding or rolling along rock surfaces.…”

Section: Introductionmentioning

confidence: 97%

Particle mobilization in porous media: Temperature effects on competing electrostatic and drag forces

You

Bedrikovetsky

Badalyan

et al. 2015

Geophysical Research Letters

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108

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The fluid flow in natural reservoirs mobilizes fine particles. Subsequent migration and straining of the mobilized particles in rocks greatly reduce reservoir permeability and well productivity. This chain of events typically occurs over the temperature ranges of 20–40°C for aquifers and 120–300°C for geothermal reservoirs. However, the present study might be the first to present a quantitative analysis of temperature effects on the forces exerted on particles and of the resultant fines migration. Based on torque balance between electrostatic and drag forces acting on attached fine particles, we derived a model for the maximum retention concentration and used it to characterize the detachment of multisized particles from rock surfaces. Results showed that electrostatic force is far more affected than water viscosity by temperature variation. An analytical model for flow toward wellbore that is subject to fines migration was derived. The experiment‐based predictive modeling of the well impedance for a field case showed high agreement with field historical data (coefficient of determination R2 = 0.99). It was found that the geothermal reservoirs are more susceptible to fine particle migration than are conventional oilfields and aquifers.

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“…The normalized reciprocal to the injectivity index is called the impedance (J), which is used to describe the injectivity decline (Civan 2007;Oliveira et al 2014):…”

Section: Introductionmentioning

confidence: 99%

Injectivity Impairment During Produced Water Disposal into Low-Permeability Völkersen Aquifer (Compressibility and Reservoir Boundary Effects)

You

Kalantariasl

Schulze³

et al. 2016

SPE International Conference and Exhibition on Formation Damage Control

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Compressibility needs to be accounted for when estimating injectivity decline for water disposal in gas reservoirs and in closed aquifers, and for waterflooding of gas-condensate fields. The problem with given wellbore pressure at the injector aims avoiding the reservoir fracturing. An analytical model is developed that provides well injectivity index decline with time. Under this model, the solution of damage-free compressible flow in a closed reservoir is asymptotically matched with the impedance growth formulae for incompressible flow in the well vicinity. For the well regime of a given wellbore pressure, the injection rate decline is described by a nonlinear integro-differential equation that is solved iteratively. The solution under the field conditions investigated shows that well impedance grows faster during deep bed filtration than during external cake formation. This unusual pattern is explained by low permeability of the reservoir. Well impedance is more sensitive to the effect of formation damage than to the compressibility effect of rock and water. Lower formation damage, higher compressibility, or lower injected particle concentration results in larger total injection volume into a closed reservoir.

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Slow migration of mobilised fines during flow in reservoir rocks: Laboratory study

Cited by 98 publications

References 39 publications

Stimulation of coal seam permeability by micro-sized graded proppant placement using selective fluid properties

Stimulation of coal seam permeability by micro-sized graded proppant placement using selective fluid properties

Particle mobilization in porous media: Temperature effects on competing electrostatic and drag forces

Injectivity Impairment During Produced Water Disposal into Low-Permeability Völkersen Aquifer (Compressibility and Reservoir Boundary Effects)

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