Shear-thinning or shear-thickening fluid for better EOR? — A direct pore-scale study

Xie, Chiyu; Liu, Weifeng; Wang, Moran

doi:10.1016/j.petrol.2017.11.049

Cited by 60 publications

(26 citation statements)

References 28 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…The concept of improving the oil production by polymer flooding has always been related to viscoelasticity of water in sweep efficiency improvement. The recovery results is consistence with the limit of injection constrain of this study and shear thickening behaviour that restrain the polymer injectivity rates [28,29].…”

Section: Oil Recovery Resultssupporting

confidence: 78%

Comparative numerical study for polymer alternating gas (PAG) flooding in high permeability condition

et al. 2020

View full text Add to dashboard Cite

Polymers have been used in water alternative gas, to viscosify the water and improve the overall sweep efficiency. The use of polymer alternative gas was successful in increasing the oil production in high permeability zones. However, few practical factors affecting the field applicability have been overlooked. Therefore, this study is aimed at bridging the gap between the possibility of using several EOR such as water flooding, CO 2 flooding, water alternative gas, polymer flooding and polymer alternative gas. The research based on progressive comparison considering constant constraint. The numerical simulation STARS-CMG was used to predict the characteristics and behaviour of the fluid in the reservoir. The designed flooding pattern chosen was a single producer-single injection (P-I) scheme in homogeneous high permeable reservoir. The results of oil incremental recovery showed the following order compared to Water flooding < (3%) CO 2 flooding < (6.8%) < Water alternative gas (11.6%) Polymer flooding < (15%) Polymer alternative gas. The impact of polymer on enhancing the water alternative gas was mostly noticeable in the reduction of water cut% (83%). The controlled conformance by polymer aided in improving the sweep efficiency as indicated by the uninform U-shape. Moreover, the delayed gas breakthrough was significant and resulted in the lowest gas oil ratio of 5.17E + 04 ft3/bbl. The low gas oil ratio observation is indication of potential capturing of CO 2 in the reservoir and thus, good evidence to further implementation of CO 2 as green utilization.

show abstract

Section: Oil Recovery Resultssupporting

confidence: 78%

Comparative numerical study for polymer alternating gas (PAG) flooding in high permeability condition

et al. 2020

View full text Add to dashboard Cite

show abstract

“…Fig.6 shows a good agreement between the numerical and analytical velocities for non-Newtonian fluids using power law exponents ranging from 0.5 to 2, covering most fluids used for enhanced oil recovery (e.g. Najafi et al, 2017;Xie et al, 2018).…”

Section: Power Law Fluid Flow Through a Single Vertical Tubementioning

confidence: 66%

Pore-scale permeability prediction for Newtonian and non-Newtonian fluids

Eichheimer¹,

Thielmann²,

Попов³

et al. 2019

Preprint

View full text Add to dashboard Cite

Abstract. The flow of fluids through porous media such as groundwater flow or magma migration are key processes in geological sciences. Flow is controlled by the permeability of the rock, thus an accurate determination and prediction of its value is of crucial importance. For this reason, permeability has been measured across different scales. As laboratory measurements exhibit a range of limitations, the numerical prediction of permeability at conditions where laboratory experiments struggle has become an important method to complement laboratory approaches. At high resolutions, this prediction becomes computationally very expensive, which makes it crucial to develop methods that maximize accuracy. In recent years, the flow of non-Newtonian fluids through porous media has gained additional importance due to e.g., the use of nanofluids for enhanced oil recovery. Numerical methods to predict fluid flow in these cases are therefore required. Here, we employ the open-source finite difference solver LaMEM to numerically predict the permeability of porous media at low Reynolds numbers for both Newtonian as well as non-Newtonian fluids. We employ a stencil rescaling method to better describe the solid-fluid interface. The accuracy of the code is verified by comparing numerical solutions to analytical ones for a set of simplified model setups. Results show that stencil rescaling significantly increases the accuracy at no additional computational cost. Finally, we use our modeling framework to predict the permeability of a Fontainebleau sandstone, and demonstrate numerical convergence. Results show very good agreement with experimental estimates as well as with previous studies. We also demonstrate the ability of the code to simulate the flow of power law fluids through porous media. As in the Newtonian case, results show good agreement with analytical solutions.

show abstract

“…(see Appendix B), R is the tube radius and r the width of the tube in Cartesian coordinates. Figure 6 shows a good agreement between the numerical and analytical velocities for non-Newtonian fluids when using 0.5 and 2 as values for the power-law exponents, covering most fluids used for enhanced oil recovery (e.g., Najafi et al, 2017;Xie et al, 2018).…”

Section: Power-law Fluid Flow Through a Single Vertical Tubementioning

confidence: 73%

Pore-scale permeability prediction for Newtonian and non-Newtonian fluids

et al. 2019

View full text Add to dashboard Cite

Abstract. The flow of fluids through porous media such as groundwater flow or magma migration is a key process in geological sciences. Flow is controlled by the permeability of the rock; thus, an accurate determination and prediction of its value is of crucial importance. For this reason, permeability has been measured across different scales. As laboratory measurements exhibit a range of limitations, the numerical prediction of permeability at conditions where laboratory experiments struggle has become an important method to complement laboratory approaches. At high resolutions, this prediction becomes computationally very expensive, which makes it crucial to develop methods that maximize accuracy. In recent years, the flow of non-Newtonian fluids through porous media has gained additional importance due to, e.g., the use of nanofluids for enhanced oil recovery. Numerical methods to predict fluid flow in these cases are therefore required. Here, we employ the open-source finite difference solver LaMEM (Lithosphere and Mantle Evolution Model) to numerically predict the permeability of porous media at low Reynolds numbers for both Newtonian and non-Newtonian fluids. We employ a stencil rescaling method to better describe the solid–fluid interface. The accuracy of the code is verified by comparing numerical solutions to analytical ones for a set of simplified model setups. Results show that stencil rescaling significantly increases the accuracy at no additional computational cost. Finally, we use our modeling framework to predict the permeability of a Fontainebleau sandstone and demonstrate numerical convergence. Results show very good agreement with experimental estimates as well as with previous studies. We also demonstrate the ability of the code to simulate the flow of power-law fluids through porous media. As in the Newtonian case, results show good agreement with analytical solutions.

show abstract

Shear-thinning or shear-thickening fluid for better EOR? — A direct pore-scale study

Cited by 60 publications

References 28 publications

Comparative numerical study for polymer alternating gas (PAG) flooding in high permeability condition

Comparative numerical study for polymer alternating gas (PAG) flooding in high permeability condition

Pore-scale permeability prediction for Newtonian and non-Newtonian fluids

Pore-scale permeability prediction for Newtonian and non-Newtonian fluids

Contact Info

Product

Resources

About