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RESEARCH PAPERS

Fine-Scale Simulation of Sandstone Acidizing

[+] Author and Article Information
Chunlou Li

Department of Petroleum Engineering,  The University of Texas at Austin, 1 University Station, MC C0300, Austin, TX 78712

Tao Xie

Department of Petroleum Engineering,  The University of Texas at Austin, 1 University Station, MC C0300, Austin, TX 78712

Maysam Pournik

Department of Petroleum Engineering,  The University of Texas at Austin, 1 University Station, MC C0300, Austin, TX 78712

Ding Zhu

Department of Petroleum Engineering,  The University of Texas at Austin, 1 University Station, MC C0300, Austin, TX 78712

A. D. Hill

Department of Petroleum Engineering,  The University of Texas at Austin, 1 University Station, MC C0300, Austin, TX 78712

J. Energy Resour. Technol 127(3), 225-232 (Mar 31, 2005) (8 pages) doi:10.1115/1.1944027 History: Received August 31, 2004; Revised March 31, 2005

We have developed a fine-scale model of the sandstone core acid flooding process by solving acid and mineral balance equations for a fully three-dimensional flow field that changed as acidizing proceeded. The initial porosity and mineralogy field could be generated in a correlated manner in three dimensions; thus, a laminated sandstone could be simulated. The model has been used to simulate sandstone acidizing coreflood conditions, with a 1in.diam by 2in. long core represented by 8000 grid blocks, each having different initial properties. Results from this model show that the presence of small-scale heterogeneities in a sandstone has a dramatic impact on the acidizing process. Flow field heterogeneities cause acid to penetrate much farther into the formation than would occur if the rock were homogeneous, as is assumed by standard models. When the porosity was randomly distributed (sampled from a normal distribution), the acid penetrated up to twice as fast as in the homogeneous case. When the porosity field is highly correlated in the axial direction, which represents a laminated structure, acid penetrates very rapidly into the matrix along the high-permeability streaks, reaching the end of the simulated core as much as 17 times faster than for a homogeneous case.

Copyright © 2005 by American Society of Mechanical Engineers
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References

Figures

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Figure 1

The model gridding system

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Figure 2

3D plot of random porosity distribution

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Figure 3

Histogram of randomly distributed porosity

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Figure 4

Correlated initial porosity distribution (strong correlation in x and y directions)

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Figure 5

Δϕ for the base (homogeneous) case

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Figure 6

HF concentration at 35PV, base case

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Figure 7

Porosity distribution after 15PV, heterogeneous porosity and homogeneous mineralogy case

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Figure 8

Δϕ distribution (Δϕ>0.02) for heterogeneous porosity and homogeneous mineralogy case

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Figure 9

Δϕ for correlated porosity case (Δϕ>0.02)

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Figure 10

HF concentration distribution after 5PV, correlated porosity case

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Figure 11

Δϕ for correlated mineralogy and homogeneous porosity case

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Figure 12

Permeability evolution for random porosity cases

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Figure 13

Acid breakthrough volume for random porosity cases

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Figure 14

Acid breakthrough volume for correlated porosity cases

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Figure 15

Initial porosity field—channeling case

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Figure 16

Porosity>0.4 indicating channeling

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