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Transport in Porous Media

, Volume 68, Issue 2, pp 265–283 | Cite as

A new simulation framework for predicting the onset and effects of fines mobilization

  • Binshan JuEmail author
  • Tailiang Fan
  • Xiaodong Wang
  • Xiaofeng Qiu
Original Paper

Abstract

Fines release and migration is a universal problem in the production of oil from poorly consolidated sandstone reservoirs. This problem can result in the changes of porosity and permeability. It may not only damage a production facility, but it can also have a profound effect on oil recovery, resulting from the change in heterogeneity of the oil formation. Based on the macroscopic continuous porous media, continuity equations for multiphase flow in oil formations, and the theories of fines release and migration, a three-dimensional (3D) field scale mathematical model describing migration of fines in porous media is developed. The model is solved by a finite-difference method and the line successive over relaxation (LSOR) technique. A numerical simulator is written in Fortran 90 and it can be used to predict (1) the ratio of fines to production liquid volume, (2) the permeability change caused by colloidal and hydrodynamic forces resulting from fines release and migration, and (3) production performance. The numerical results of the one-dimensional model were verified by the data obtained by core displacement experiments. The sensitivity of numerical results with grid block size was studied by coarse grids, moderate grids, and fine grids. In addition, an oil field example with five-spot patterns was made on the numerical simulator. The results show that fines migration in an oil formation can accelerate the development of heterogeneity of the reservoir rock, and has an obvious influence on production performance, i.e., water drive front, water-cut trends, and oil recovery.

Keywords

Fines migration Permeability change Mathematical model Numerical simulator Oil recovery Water-cut 

Nomenclature

B

Volume factor of fluid

Clij

Volume concentration of composition j of particles in {the} phase l.

Csi

Mass concentration of salt ions for composition i (kg/m3)

D

Diffusivity of particle composition i (m2/s)

Ds

Diffusivity of salt, ions, (m2/s)

f

Flow efficiency factor

k

Transient absolute permeability of a porous media (m2)

kr

Relative permeability of a porous media

p

Pressure (Pa)

q

Production/injection rate (m3/s)

R

Net particle change rate on the pore surfaces or at pore throats (1/s)

Rs

Solution gas–oil ratio

S

Saturation

t

Time (s)

v

Flow rate (m/s)

vc

Critical velocity (m/s)

x

Distance (m)

z

Distance from reference level (m)

αc

Release rate of fines by colloidal forces (s−1)

αd

Rate constant for the deposition of particles on pore surfaces (m−1)

αf

Coefficient of flow efficiency

αh

Release rate of fines by hydrodynamic forces (m−1)

αp

Capture rate constant of particles at pore throats (m−1)

δlij

Volume of particles deposited on the pore surfaces per unit bulk volume

\(\phi\)

Porosity of the porous media

\(\delta_{lij}^\ast\)

Volume of particles trapped at throats per unit bulk volume.

γ

Specific gravity of fluids.

λf

Constant for fluid seepage allowed by the plugged pores

μ

Viscosity of fluid (Pa·s)

Subscripts

0

Initial value

c

Critical value or capillary pressure

d

Deposition

e

Entrainment

fe

Flow efficiency

g

Gas

h

Hydrodynamics

i

Wettability

j

One component

o

Oil

p

Pore throat

w

Water

SI Conversion factors

1 cm = 1 × 10−2 m

 

1 MPa = 1 × 106 Pa

 

1 mPa = 1 × 10−3 Pa

 

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Copyright information

© Springer Science+Business Media, Inc. 2006

Authors and Affiliations

  • Binshan Ju
    • 1
    Email author
  • Tailiang Fan
    • 1
  • Xiaodong Wang
    • 1
  • Xiaofeng Qiu
    • 2
  1. 1.School of Energy ResourceChina University of GeosciencesHaidian districtChina
  2. 2.China University of PetroleumDongyingChina

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