scholarly journals A New Method of Central Axis Extracting for Pore Network Modeling in Rock Engineering

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-20
Author(s):  
Xiao Guo ◽  
Kairui Yang ◽  
Haowei Jia ◽  
Zhengwu Tao ◽  
Mo Xu ◽  
...  
Keyword(s):  
Network Modeling ◽  
Cutting Plane ◽  
Rock Cutting ◽  
Pore Network ◽  
Central Axis ◽  
Geometric Transformation ◽  
Pore Network Model ◽  
Pore Network Modeling ◽  
Extraction Algorithm ◽  
Digital Core

Characterizing internal microscopic structures of porous media is of vital importance to simulate fluid and electric current flow. Compared to traditional rock mechanics and geophysical experiments, digital core and pore network modeling is attracting more interests as it can provide more details on rock microstructure with much less time needed. The axis extraction algorithm, which has been widely applied for pore network modeling, mainly consists of a reduction and burning algorithm. However, the commonly used methods in an axis extraction algorithm have the disadvantages of complex judgment conditions and relatively low operating efficiency, thus losing the practicality in application to large-scale pore structure simulation. In this paper, the updated algorithm proposed by Palágyi and Kuba was used to perform digital core and pore network modeling. Firstly, digital core was reconstructed by using the Markov Chain Monte Carlo (MCMC) method based on the binary images of a rock cutting plane taken from heavy oil reservoir sandstone. The digital core accuracy was verified by comparing porosity and autocorrelation function. Then, we extracted the central axis of the digital pore space and characterize structural parameters through geometric transformation technology and maximal sphere method. The obtained geometric parameters were further assigned to the corresponding nodes of pore and throat on the central axis of the constructed model. Moreover, the accuracy of the new developed pore network model was measured by comparing pore/throat parameters, curves of mercury injection, and oil-water relative permeability. The modeling results showed that the new developed method is generally effective for digital core and pore network simulation. Meanwhile, the more homogeneity of the rock, which means the stronger “representative” of binary map the rock cutting plane, the more accurate simulated results can be obtained.

Multiscale Reconstruction of Vuggy Carbonates by Pore-Network Modeling and Image-Based Technique

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 253-267 ◽  
Author(s):  
Saeid Sadeghnejad ◽  
Jeff Gostick
Keyword(s):  
Flow Behavior ◽  
Network Modeling ◽  
Pore Network ◽  
Absolute Permeability ◽  
Pore Network Model ◽  
Pore Scale ◽  
Secondary Porosity ◽  
Pore Network Modeling ◽  
Carbonate Formation ◽  
The Absolute

Summary Vugular carbonate rocks have a complicated flow behavior because of their multimodal porosity system, with different interconnectivity at the pore scale. In this study, a new hybrid algorithm to reconstruct a bimodal vugular porous medium is introduced by coupling the pore-network modeling approach (i.e., stochastic) with the image-based network technique (i.e., process-based). This work implements image-processing techniques to generate a lattice-based network of secondary porosity (i.e., vugs) on top of an initial pore-network model at the pore scale. The resulting multiscale model is designed to preserve vug-to-vug and vug-to-pore connectivity of overlapping vugs. Modifying the effective conductance of the overlapped vugs enables the calculation of permeability of the dual-porosity network by applying mass conservation and the Poiseuille law. The method is validated on samples from an Iranian carbonate formation. The matrix micropores obtained from the mercury-intrusion laboratory measurements are statistically reconstructed by a Nelder-Mead optimization algorithm. Our results show that during the addition of vugs into a network, the absolute permeability of the network increases monotonically with rising porosity before vug percolation. However, once vuggy pores percolate, the absolute permeability of the network increases tremendously. Moreover, the availability of vugs makes the network structure more complex as determined by the off-diagonal complexity measure. The results of this study help in understanding the behavior of vuggy formations observed in carbonate reservoirs.

Pore Network Modeling of a Polymer Flooding Microscopic Seepage Mechanism

2011 ◽  
Vol 29 (17) ◽  
pp. 1803-1810 ◽  
Author(s):  
C. Z. Sun ◽  
H. Q. Jiang ◽  
J. J. Li ◽  
S. J. Ye
Keyword(s):  
Network Modeling ◽  
Pore Network ◽  
Polymer Flooding ◽  
Pore Network Modeling

Relationship between Residual Saturations and Wettability using Pore-Network Modeling

2021 ◽  
Author(s):  
Prakash Purswani ◽  
Russell T. Johns ◽  
Zuleima T. Karpyn
Keyword(s):  
Contact Angle ◽  
Oil Recovery ◽  
Network Modeling ◽  
Pore Network ◽  
Residual Oil ◽  
Residual Saturation ◽  
Oil Saturation ◽  
Pore Network Modeling ◽  
Residual Oil Saturation ◽  
Eor Processes

Abstract The relationship between residual saturation and wettability is critical for modeling enhanced oil recovery (EOR) processes. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Coreflooding experiments have shown that residual oil saturation trends against wettability indices typically show a minimum around mixed-wet conditions. Amott indices, however, provides an average measure of wettability (contact angle), which are intrinsically dependent on a variety of factors such as the initial oil saturation, aging conditions, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore network modeling (PNM), we show that residual oil saturation varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the residual oil saturation decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, calculation of Amott indices for the PNM data sets show that a plot of the residual oil saturation versus Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. This can have important implications for low salinity waterflooding or other EOR processes where wettability is altered.

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