Non-Newtonian Multiphase Flow in Carbonates, A Generalized Coupled Experimental and Modeling Workflow at Pore Levels

Nara Brandão Costa Santos1, Arsalan Zolfaghari2, Fábio de Oliveira Arouca1, João Jorge Ribeiro Damasceno1, Amirmasoud Kalantari Dahaghi2, and Shahin Negahban2

1) Chemical Engineering, Uberlândia Federal University, Uberlândia, MG, BR

2) Chemical and Petroleum Engineering, University of Kansas, Lawrence, KS, USA

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Key Findings

A series of experiments were conducted to investigate the flow of Xanthan Gum (XG) under single and multiphase flow conditions where gravity segregation played a significant role in the saturation profiles across the height of the core samples.

Having a bimodal pore size distribution in the carbonate samples, XG and oil globule size distributions were different at the pore scales.

The microporosity regions would drastically impact the connectivity of the wetting phase, and hence, the calculated formation factor.

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Significance

The increase in energy demand has been boosting the improvement of the extraction and processing of energy resources. In the oil industry, the drilling of a well corresponds to an expensive financial investment in the exploration stage. In that scenario, understanding the behavior of drilling fluids in the inner filter cake formation is an important key to mitigate formation damage (Kaiser, 2009).

The inner filter cake is formed by mud fluid phase and small cuttings that passes through the reservoir pores during an overbalanced drilling operation. The formation of the cake controls fluid loss which consequently limits reservoir fluids contamination and pore-level blockage of the fluid paths during production (Committee, 2005).

This study is specifically designed to investigate the impact of fluid saturation on the cake formation at pore levels. To do this, we inject several aqueous solutions of the Xanthan Gum (XG) at different concentrations into miniature core plugs of a carbonate rock sample analogous to the Brazilian pre-salt formations. High-resolution X-ray micro-computed tomography (micro-CT) is used to investigate multiphase pore fluid occupancies at different saturations and initial conditions. Two sets of images were acquired at each saturation stage to improve the phases’ segmentation, i.e., reference and target state images. In this study, we introduce several novel image analysis techniques with regards to image registrations and segmentations.

In this study, we are primarily interested to understand polymeric fluid flow through porous media by probing the impact of pore space topology, polymer concentration, and initial saturation of samples prior to the XG injections. We design several experiments to measure saturation profiles and pressure drops across the samples under different saturation history profiles.

Besides the experimental evaluation, different modeling approaches have been used for the pore-scale modeling of multiphase flow in carbonates. One of these models is pore network models which are inherently challenging due to the problem of the scale. A multi-scale network extraction technique can be used to generate pore networks representing different scales that are important in the flow and electric transport of these porous media. Large-scale networks are then used to simulate multiphase flow at pore levels. For smaller networks (<300,000 elements) our in-house code will be used to simulate three-phase flow simulations covering a wide range of saturation space. For larger networks, we can run two-phase flow simulations on a cluster using e-Core software compatible with our generated pore network models at different scales. More results will be presented in the future on the large-scale pore network modeling of two-phase flow simulations and smaller-scale modeling of three-phase flow simulations.

Methodology

Three separate core samples of carbonate rock (Helium total porosity of 0.386 and permeability of 221.2 mD) were placed inside of an aluminum core holder. We report the permeability of each miniature core plugs by recording the pressure drop values across the core at different flow rates under single-phase flow conditions. Two different XG aqueous solutions (i.e., 0.2 and 0.4% w/w) were then prepared and injected in these three different core samples named CH1 and CH2, and CH3.

We have injected XG into cores with two different initial conditions, i.e., single- and two-phase flow conditions. For the single-phase condition (i.e., CH1 and 2), we inject XG into a fully saturated core with water. For the sample of CH3, XG was injected after a drainage process. Here are the accounts of steps that were taken for the core holders 1 and 2: cores are fully saturated with carbon dioxide (CO2) by flowing several pore volumes of the gas through the core; water is then injected to displace CO2 while raising the pressure occasionally to dissolve any trapped cluster; XG is then injected under the pressure of 300 psi; reference scans are collected; oil is then injected to displace XG (at 3 different stages); and final stage of XG injection is performed with P = 350 psi. For the two-phase flow test (in CH3), oil was injected at the first stage after saturating the core with water. This has prepared the initial state of the pore space before XG injection. After XG injection, oil is then injected to investigate XG displacement. In all experiments, oil phase was doped with 8% v/v Iodooctane to generate enough X-ray contrasts between XG and oil (Arshadi et al, 2017). Figure 1 illustrates the experimental apparatus of this work.

Figure 1: Schematic diagram of the experimental setup used in this work for the polymeric fluid injection process

A HeliScan micro-CT imaging system with a dedicated feedthrough aperture and limited stage rotation capability was used in this work. We used a double helix trajectory to acquire images with a resolution of 7.15 µm. Region of Interest (ROI) imaging technique was used for the sample of CH3 to enable visualization of the microporosity regions at higher resolutions (i.e., 2.15 µm).

The X-ray images were filtered, registered, segmented, and analyzed for fluid saturation profiles, pore fluid occupancy, and globule size analyses across the sample using PerGeos software. The registration step is aimed to align the target image (at a given saturation stage) with its reference image (at its single-phase condition). This stage is done using manual and computational transformation tools. As part of fluid segmentation processes, we eliminate partial volume effects using a novel procedure.

Results

Figure 2 illustrates a two-dimensional cross-sectional image of a 3D micro-tomogram after oil to XG displacements. These images, in 3D, are analyzed to obtain meaningful statistical properties that can be translated into physical phenomena.

Figure 2: Pore level image of the sample after oil injection into XG

Figure 3 shows the Xanthan Gum and oil saturation profiles at the end of each injection cycle in CH1. All injections were done from the top port. Comparing oil and XG saturations at a given height, we see signatures of gravity segregation between phases at pore levels.

Concerning the XG displacement after the first (XG_Oil1), second (XG_Oil2), and third (XG_Oil3) oil injections, its saturation profile showed narrowed variation than the ones corresponds to the first (XG_1) and second (XG_2) XG injections, respectively.

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Figure 3: Saturation profile: (a) Xanthan Gum; (b) Oil.

Next, we present the size distribution of the pores containing specific fluids in Figure 4. To generate this figure, we first segmented XG and oil from the target image. We then overlay this segmented image on the extracted pores from the reference image and tag the pores based on being occupied by oil or XG. Note that a pore can belong to both families if it holds both of XG and oil simultaneously. The Xanthan Gum from its first injection and the oil injections exhibit a bimodal curve while the remaining XG saturations show monomodal behavior.

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Figure 4: Size distribution of the pores containing (a) Xanthan Gum, and (b) oil in CH1

Next, we analyze the connectivity of each phase in 3D. We note that most of the XG were disconnected after oil injection. We believe the presence of the fracture in the sample, as well as the observed gravity segregation, impact the discontinuity of XG after oil injection. Conversely, the oil globule exhibited more connectivity across the whole sample height. The globule images are illustrated in Figure 5 shown below.

Figure 5: Xanthan Gum and oil globules.

The modeling approach, in the present work, a volume of fluid (VOF) method coupled with an adaptive meshing technique was used to perform the pore-scale simulation on a 3D X-ray micro-tomography (CT) images of rock samples. The numerical model is based on the resolution of the Navier-Stokes equations along with a phase fraction equation incorporating the dynamics contact model. The simulations of a single-phase flow for the absolute permeability showed a good agreement with the literature benchmark. Subsequently, the code was used to simulate a two-phase flow consisting of a polymer solution, displaying a shear-thinning power-law viscosity.

Other experiments that were conducted in this study was CH2 with different XG concentration (i.e., 0.4 % w/w) as well as CH3 with intial two-phase flow condition.

Conclusions

We performed a three-stage experiment to investigate the dynamic behavior of the non-Newtonian fluid flow under single and multiphase flow conditions. We successfully segmented XG and oil at pore levels reporting saturation and size distribution profiles of different phases. The size distribution of pores occupied by Xanthan Gum and oil showed a bimodal characteristic, while the residual XG showed a monomodal one. The first Xanthan Gum injection and oil flows revealed phase connectivity, and the residual XG globules were mainly disconnected. On the simulation side, we investigated the impact of consistency factor (K), the behavior index (n), along with the two contact angles (advancing and receding) on the relative permeability.

References

Arshadi, M., Shahrak, A.Z., Piri, M., Al-Muntasheri, G.A., Sayed, M., 2017, The effect of deformation on two-phase flow through proppant-packed fracture shale samples: A micro-scale experimental investigation: Advances in Water Resources, v. 105, p.108-31.

Blunt, M.J., 2017, Multiphase Flow in Permeable Media: A Pore Scale Perspective. Cambridge University Press, 519 p.

Committee, A.S.S., 2005, Drilling Fluids Processing Handbook. Elsevier, 693 p.

Kaiser, M.J., 2009, Modeling the time and cost to drill an offshore well, Energy, v. 34, p. 1097-1112.

KICC 2020 Annual Virtual Meeting – Extended Abstracts

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