scholarly journals Influence of Stress Sensitivity on Water-Gas Flow in Carbonate Rocks

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-12
Author(s):  
Shuaishi Fu ◽  
Lianjin Zhang ◽  
Yingwen Li ◽  
Xuemei Lan ◽  
Roohollah Askari ◽  
...  
Keyword(s):  
Carbonate Rocks ◽  
Gas Flow ◽  
Two Phase Flow ◽  
Water Saturation ◽  
Early Stage ◽  
Confining Pressure ◽  
Gas Production ◽  
Pore Network Model ◽  
Phase Flow ◽  
Two Phase

Carbonate reservoirs significantly contribute to exploitation. Due to their strong heterogeneity, it is of great significance to study core seepage capacity and gas-water two-phase flow of reservoirs with various pore structures under different stresses for productivity prediction, gas reservoir development, and reservoir protection. We utilize micrometer-resolution X-ray tomography to obtain the digital rocks of porous, fractured-porous, and fractured-vuggy carbonate rocks during pressurized process and depressurization. The Lattice Boltzmann method and pore network model are used to simulate the permeability and gas-water two-phase flow under different confining pressures. We show that at the early stage of pressure increase, fractures, vugs, or large pores as the main flow channels first undergo compaction deformation, and the permeability decreases obviously. Then, many isolated small pores are extruded and deformed; thus, the permeability reduction is relatively slow. As the confining pressure increases, the equal-permeability point of fractured-porous sample moves to right. At the same confining pressure, the water saturation corresponding to equal-permeability point during depressurization is greater than that of pressurized process. It is also proved that the pore size decreases irreversibly, and the capillary force increases, which is equivalent to the enhancement of water wettability. Therefore, the irreversible closure of pores leads to the decrease of permeability and the increase of gas-phase seepage resistance, especially in carbonate rocks with fractures, vugs, and large pores. The findings of this study are helpful to better understand the gas production law of depletion development of carbonate gas reservoirs and provide support for efficient development.

Optic Imaging of Two-Phase-Flow Behavior in 1D Nanoscale Channels

SPE Journal ◽  
2014 ◽  
Vol 19 (05) ◽  
pp. 793-802 ◽  
Author(s):  
Qihua Wu ◽  
Baojun Bai ◽  
Yinfa Ma ◽  
Jeong Tae Ok ◽  
Keith B. Neeves ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Shale Gas ◽  
Two Phase Flow ◽  
Water Saturation ◽  
Flow Behavior ◽  
Gas Production ◽  
Production Optimization ◽  
Phase Flow ◽  
Two Phase ◽  
Small Pore

Summary Gas in tight sand and shale exists in underground reservoirs with microdarcy (µd) or even nanodarcy (nd) permeability ranges; these reservoirs are characterized by small pore throats and crack-like interconnections between pores. The size of the pore throats in shale may differ from the size of the saturating-fluid molecules by only slightly more than one order of magnitude. The physics of fluid flow in these rocks, with measured permeability in the nanodarcy range, is poorly understood. Knowing the fluid-flow behavior in the nanorange channels is of major importance for stimulation design, gas-production optimization, and calculations of the relative permeability of gas in tight shale-gas systems. In this work, a laboratory-on-chip approach for direct visualization of the fluid-flow behavior in nanochannels was developed with an advanced epi-fluorescence microscopy method combined with a nanofluidic chip. Displacements of two-phase flow in 100-nm-depth slit-like channels were reported. Specifically, the two-phase gas-slip effect was investigated. Under experimental conditions, the gas-slippage factor increased as the water saturation increased. The two-phase flow mechanism in 1D nanoscale slit-like channels was proposed and proved by the flow-pattern images. The results are crucial for permeability measurement and understanding fluid-flow behavior for unconventional shale-gas systems with nanoscale pores.

scholarly journals Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Ershe Xu ◽  
Lingjie Yu ◽  
Ming Fan ◽  
Tianyu Chen ◽  
Zhejun Pan ◽  
...  
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Two Phase Flow ◽  
Water Injection ◽  
Injection Pressure ◽  
Gas Production ◽  
Phase Flow ◽  
Injection Time ◽  
Two Phase ◽  
Proposed Model

In this work, a triple-porosity, two-phase flow model was established to fill the knowledge gap of previous models focusing on gas production characteristics while ignoring the impacts of water injection. The proposed model considers the water flow in the fracture systems and clay minerals and the gas flow in the organic matter, inorganic pore, and fracture systems. The proposed model is solved using a finite element approach with COMSOL Multiphysics (Version 5.6) and verified with field data. Then, the evolutions of the intrinsic and relative permeabilities during water injection and gas production are examined. Furthermore, the impacts of water injection time and pressure are investigated. Good verification results are obtained; the goodness-of-fit value is 0.92, indicating that the proposed model can replicate both the water stimulation and the gas production stages. The relative gas permeability declines during water injection but recovers in the gas depletion stage. Furthermore, the intrinsic permeability increases during the water injection stage but decreases during the gas production stage. A higher water injection pressure and longer injection time would enlarge the intrinsic permeability, thus improving flow capacity. However, it would reduce gas relative permeability, thereby hindering gas flow. The shale gas production characteristic is controlled by the two abovementioned competing mechanisms. There exists a perfect combination of water injection pressure and injection time for achieving the maximum profitability of a shale gas well. This work can give a better understanding of the two-phase flow process in shale reservoirs and shed light on the field application of hydraulic fracturing.

The influence of the Stokes and Archimedes forces on the stability of a two-phase flow

2003 ◽  
Vol 3 ◽  
pp. 266-270
Author(s):  
B.H. Khudjuyerov ◽  
I.A. Chuliev
Keyword(s):  
Spectral Method ◽  
Stability Region ◽  
Gas Flow ◽  
Two Phase Flow ◽  
Solid Phase ◽  
Stability Characteristic ◽  
Phase Flow ◽  
Two Phase ◽  
The Stability

The problem of the stability of a two-phase flow is considered. The solution of the stability equations is performed by the spectral method using polynomials of Chebyshev. A decrease in the stability region gas flow with the addition of particles of the solid phase. The analysis influence on the stability characteristic of Stokes and Archimedes forces.

Imaging and Resistivity Studies of Saturation Gradients in Two-Phase Flow in 3-D Porous Media

1996 ◽  
Vol 464 ◽  
Author(s):  
E. H. Kawamoto ◽  
Po-Zen Wong
Keyword(s):  
Computed Tomography ◽  
Porous Media ◽  
Two Phase Flow ◽  
Water Saturation ◽  
Glass Beads ◽  
Water Phase ◽  
Phase Flow ◽  
Two Phase ◽  
Vertical Column ◽  
X Ray

ABSTRACTWe have carried out x-ray radiography and computed tomography (CT) to study two-phase flow in 3-D porous media. Air-brine displacement was imaged for drainage and imbibition experiments in a vertical column of glass beads. By correlating water saturation Sw with resistance R, we find that there is a threshold saturation S* ≈ 0.2, above which R(SW) ∼ Sw−2, in agreement with the empirical Archie relation. This holds true for both drainage and imbibition with littlehysteresis, provided that Sw remains above S*. Should Sw drop below S* during drainage, R(Sw) rises above the Archie prediction, exhibiting strong hysteresis upon reimbibition. This behavior suggests a transition in the connectivity of the water phase near S*, possibly due to percolation effects.

Massive fines detachment induced by moving gas-water interfaces during early stage two-phase flow in coalbed methane reservoirs

Fuel ◽  
2018 ◽  
Vol 222 ◽  
pp. 193-206 ◽  
Author(s):  
Fansheng Huang ◽  
Yili Kang ◽  
Lijun You ◽  
Xiangchen Li ◽  
Zhenjiang You
Keyword(s):  
Coalbed Methane ◽  
Two Phase Flow ◽  
Early Stage ◽  
Phase Flow ◽  
Two Phase

Experimental, Numerical, and Statistical Investigation of Two Phase Flow in a Cylindrical Perforation Tunnel

2021 ◽  
Author(s):  
Ekhwaiter Abobaker ◽  
Abadelhalim Elsanoose ◽  
Mohammad Azizur Rahman ◽  
Faisal Khan ◽  
Amer Aborig ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Steady State ◽  
Statistical Analysis ◽  
Flow Rate ◽  
Gas Flow ◽  
Two Phase Flow ◽  
Phase Flow ◽  
Gas Flow Rate ◽  
Two Phase ◽  
Flow Through

Abstract Perforation is the final stage in well completion that helps to connect reservoir formations to wellbores during hydrocarbon production. The drilling perforation technique maximizes the reservoir productivity index by minimizing damage. This can be best accomplished by attaining a better understanding of fluid flows that occur in the near-wellbore region during oil and gas operations. The present work aims to enhance oil recovery by modelling a two-phase flow through the near-wellbore region, thereby expanding industry knowledge about well performance. An experimental procedure was conducted to investigate the behavior of two-phase flow through a cylindrical perforation tunnel. Statistical analysis was coupled with numerical simulation to expand the investigation of fluid flow in the near-wellbore region that cannot be obtained experimentally. The statistical analysis investigated the effect of several parameters, including the liquid and gas flow rate, liquid viscosity, permeability, and porosity, on the injection build-up pressure and the time needed to reach a steady-state flow condition. Design-Expert® Design of Experiments (DoE) software was used to determine the numerical simulation runs using the ANOVA analysis with a Box-Behnken Design (BBD) model and ANSYS-FLUENT was used to analyses the numerical simulation of the porous media tunnel by applying the volume of fluid method (VOF). The experimental data were validated to the numerical results, and the comparison of results was in good agreement. The numerical and statistical analysis demonstrated each investigated parameter’s effect. The permeability, flow rate, and viscosity of the liquid significantly affect the injection pressure build-up profile, and porosity and gas flow rate substantially affect the time required to attain steady-state conditions. In addition, two correlations obtained from the statistical analysis can be used to predict the injection build-up pressure and the required time to reach steady state for different scenarios. This work will contribute to the clarification and understanding of the behavior of multiphase flow in the near-wellbore region.

scholarly journals Iterative Analytical Solutions for Nonlinear Two-Phase Flow with Gas Solubility in Shale Gas Reservoirs

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-15 ◽  
Author(s):  
Xiaoji Shang ◽  
J. G. Wang ◽  
Zhizhen Zhang
Keyword(s):  
Capillary Pressure ◽  
Analytical Solutions ◽  
Shale Gas ◽  
Nonlinear Term ◽  
Two Phase Flow ◽  
Gas Production ◽  
Phase Flow ◽  
Gas Solubility ◽  
Production Rates ◽  
Two Phase

The governing equations of a two-phase flow have a strong nonlinear term due to the interactions between gas and water such as capillary pressure, water saturation, and gas solubility. This nonlinearity is usually ignored or approximated in order to obtain analytical solutions. The impact of such ignorance on the accuracy of solutions has not been clear so far. This study seeks analytical solutions without ignoring this nonlinear term. Firstly, a nonlinear mathematical model is developed for the two-phase flow of gas and water during shale gas production. This model also considers the effects of gas solubility in water. Then, iterative analytical solutions for pore pressures and production rates of gas and water are derived by the combination of travelling wave and variational iteration methods. Thirdly, the convergence and accuracy of the solutions are checked through history matching of two sets of gas production data: a China shale gas reservoir and a horizontal Barnett shale well. Finally, the effects of the nonlinear term, shale gas solubility, and entry capillary pressure on the shale gas production rate are investigated. It is found that these iterative analytical solutions can be convergent within 2-3 iterations. The solutions can well describe the production rates of both gas and water. The nonlinear term can significantly affect the forecast of shale gas production in both the short term and the long term. Entry capillary pressure and shale gas solubility in water can also affect shale gas production rates of shale gas and water. These analytical solutions can be used for the fast calculation of the production rates of both shale gas and water in the two-phase flow stage.

Based on the Pore Network Model of CO2-Water-Quartz System Two-Phase Flow Characteristics Study

2014 ◽  
Vol 962-965 ◽  
pp. 1289-1292 ◽  
Author(s):  
Ling Yu Chen ◽  
Yu Liu ◽  
Meiheriayi Mutailipu
Keyword(s):  
Network Model ◽  
Two Phase Flow ◽  
Flow Characteristics ◽  
Pore Network ◽  
Pore Network Model ◽  
Phase Flow ◽  
Saline Aquifer ◽  
Two Phase ◽  
Aquifer Storage ◽  
Relative Permeability Curves

Saline aquifer storage is considered to be one of the main ways to realize CO2 geological sequestration. The purpose of the paper is to research CO2 and water seepage characteristics under the condition of different pressure and diameter of glass sand. First, establish four kinds of sand packed beds pore network model. Secondly, measuring the gas-liquid interfacial tension, contact angle under the condition of 50°C and different pressure (5-20MPa). Finally, using the two-phase flow model, obtain the gas-liquid two-phase relative permeability curves under different conditions. The simulation results of this paper can help to predict the actual saline aquifer storage of CO2 sequestration.

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