A fractal model to describe the evolution of multiphase flow properties during mineral dissolution

AbstractCarbon dioxide injection into deep saline aquifers is governed by a number of physico-chemical processes including mineral dissolution and precipitation, multiphase fluid flow, and capillary trapping. These processes can be coupled; however, the impact of fluid–rock reaction on the multiphase flow properties is difficult to study and is not simply correlated with variations in porosity. We observed the impact of rock mineral dissolution on multiphase flow properties in two carbonate rocks with distinct pore structures. Observations of steady-state $$\hbox {N}_2$$N2–water relative permeability and residual trapping were obtained, along with mercury injection capillary pressure characteristics. These tests alternated with eight stages in which 0.5% of the mineral volume was uniformly dissolved into solution from the rock cores using an aqueous solution with a temperature-controlled acid. Variations in the multiphase flow properties did not relate simply to changes in porosity, but corresponded to the changes in the underlying pore structure. In the Ketton carbonate, dissolution resulted in an increase in the fraction of pore volume made up by the smallest pores and a decrease in the fraction made up by the largest pores. This resulted in an increase in the relative permeability to the nonwetting phase, a decrease in the relative permeability to the wetting phase, and a modest, but systematic decrease in residual trapping. In the Estaillades carbonate, dissolution resulted in an increase in the fraction of pore volume made up by pores in the central range of the initial pore size distribution, and a corresponding decrease in the fraction made up by both the smallest and largest pores. This resulted in a decrease in the relative permeability to both the wetting and nonwetting fluid phases and no discernible impact on the residual trapping. In summary, the impact of rock matrix dissolution will be strongly dependent on the impact of that dissolution on the underlying pore structure of the rock. However, if the variation in pore structure can be observed or estimated with modelling, then it should be possible to estimate the impacts on multiphase flow properties.

Download Full-text

A Fractal Model for Predicting the Relative Permeability of Rough-Walled Fractures

Advances in Civil Engineering ◽

10.1155/2021/6623275 ◽

2021 ◽

Vol 2021 ◽

pp. 1-10

Author(s):

Zuyang Ye ◽

Wang Luo ◽

Shibing Huang ◽

Yuting Chen ◽

Aiping Cheng

Keyword(s):

Porous Media ◽

Multiphase Flow ◽

Relative Permeability ◽

Fractal Model ◽

Numerical Results ◽

Flow Paths ◽

Capillary Model ◽

Lognormal Distributions ◽

Fractal Characteristics ◽

Aperture Distribution

The relative permeability and saturation relationships through fractures are fundamental for modeling multiphase flow in underground geological fractured formations. In contrast to the traditional straight capillary model from porous media, the realistic flow paths in rough-walled fractures are tortuous. In this study, a fractal relationship between relative permeability and saturation of rough-walled fractures is proposed associated with the fractal characteristics of tortuous parallel capillary plates, which can be generalized to several existing models. Based on the consideration that the aperture distribution of rough-walled fracture can be represented by Gaussian and lognormal distributions, aperture-based expressions between relative permeability and saturation are explicitly derived. The developed relationships are validated by the experimental observations on Gaussian distributed fractures and numerical results on lognormal distributed fractures, respectively.

Download Full-text

Multiphase flow in tight sandstone: An improved application for 3D intermingled fractal model

Journal of Petroleum Science and Engineering ◽

10.1016/j.petrol.2019.02.030 ◽

2019 ◽

Vol 177 ◽

pp. 403-414 ◽

Cited By ~ 2

Author(s):

Caoxiong Li ◽

Mian Lin ◽

Lili Ji ◽

Wenbin Jiang

Keyword(s):

Multiphase Flow ◽

Fractal Model ◽

Tight Sandstone

Download Full-text

A NEW RELATIVE PERMEABILITY MODEL OF UNSATURATED POROUS MEDIA BASED ON FRACTAL THEORY

Fractals ◽

10.1142/s0218348x20500024 ◽

2020 ◽

Vol 28 (01) ◽

pp. 2050002

Author(s):

KE CHEN ◽

HE CHEN ◽

PENG XU

Keyword(s):

Experimental Data ◽

Porous Media ◽

Fractal Dimension ◽

Multiphase Flow ◽

Relative Permeability ◽

Volume Fraction ◽

Fractal Model ◽

Accurate Estimation ◽

Unsaturated Porous Media ◽

Flow Through

The multiphase flow through unsaturated porous media and accurate estimation of relative permeability are significant for oil and gas reservoir, grounder water resource and chemical engineering, etc. A new fractal model is developed for the multiphase flow through unsaturated porous media, where multiscale pore structure is characterized by fractal scaling law and the trapped water in the pores is taken into account. And the analytical expression for relative permeability is derived accordingly. The relationships between the relative permeability and capillary head as well as saturation are determined. The proposed model is validated by comparison with 14 sets of experimental data, which indicates that the fractal model agrees well with experimental data. It has been found that the proposed fractal model shows evident advantages compared with BC-B model and VG-M model, especially for the porous media with fine content and texture. Further calculations show that water permeability decreases as the fractal dimension increases under fixed saturation because the cumulative volume fraction of small pores increases with the increment of the fractal dimension. The present fractal model for the relative permeability may be helpful to understand the multiphase flow through unsaturated porous media.

Download Full-text

Three-Dimensional Numerical Simulation of Multiscale Fractures and Multiphase Flow in Heterogeneous Unconventional Reservoirs with Coupled Fractal Characteristics

Geofluids ◽

10.1155/2021/8265962 ◽

2021 ◽

Vol 2021 ◽

pp. 1-15

Author(s):

Hong Li ◽

Haiyang Yu ◽

Nai Cao ◽

Shiqing Cheng ◽

He Tian ◽

...

Keyword(s):

Numerical Simulation ◽

Multiphase Flow ◽

Water Saturation ◽

Three Dimensional ◽

Horizontal Wells ◽

Simulation Method ◽

Fractal Model ◽

Point Pattern ◽

Permeability Model ◽

Heterogeneous Model

A simulated reservoir model, based on the permeability fractal model and three-dimensional (3D) Gaussian filter, was established to account for in-layer and interlayer heterogeneity so that the result conforms to the law of geological statistics. Combined with an embedded discrete fracture method (EDFM), a multiscale fracture system was established, forming the numerical simulation method of multiphase flow in horizontal wells in heterogeneous reservoirs with complex fractures. The heterogeneity and saturation of the reservoir mixed five-point pattern of vertical and horizontal wells and the injection and production of horizontal wells were discussed. The results show that it is difficult to characterize complex reservoirs using a homogeneous permeability model. Thus, it is best to use a heterogeneous model that considers permeability differences in tight reservoirs. Formation fluids coexist in multiple phases, and water saturation has a direct effect on the production. Thus, a multiphase flow model is needed and can play a greater role in injection and production technology. The mixed five-point pattern of vertical and horizontal wells can improve productivity to a certain extent, but the dual effects of heterogeneity and fracturing will cause a decline in production by accelerating the communication of injected fluid. The reservoir is heterogeneous between wells, and there are differing effects on adjacent wells. Therefore, near-well natural microfractures are opened because of fracturing in horizontal wells, and the heterogeneity cannot be ignored, especially when multiple wells are simultaneously injected and produced.

Download Full-text