scholarly journals Nanoconfined Water in Shales and Its Impact on Real Gas Flow

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-18
Author(s):  
Yudan Li ◽  
Shaohua Gu ◽  
Cheng Dai
Keyword(s):  
Porous Media ◽  
Gas Flow ◽  
High Pressures ◽  
Film Flow ◽  
Gas Transport ◽  
Transport Model ◽  
Water Film ◽  
Real Gas ◽  
The Real ◽  
Nanoconfined Water

The presence of water, i.e., connate or hydraulic fracturing water, along with the gaseous hydrocarbons in shale nanopores is largely overlooked by previous studies. In this work, a new unified real gas-transport model has been developed for both organic and inorganic porous media accounting for the nanoconfined water film flow. More specifically, a gas core flows in the center of the organic/inorganic pore surrounded by a water film which can be further divided into an interfacial region (near-wall water) and bulk region (bulk water). We differentiate the varying water viscosity between the two regions and consider disparate slip boundaries; that is, the near-wall water can slip along the hydrophobic organic pore surface while it is negligible in hydrophilic inorganic pores. Incorporating modified boundary conditions into the Navier-Stokes equations, gas transport model through single organic/inorganic pore is derived. The model is also comprehensively scaled up to the porous media scale considering the porosity, tortuosity, and total organic carbon (TOC) contents. Results indicate that the gas flow capacity decreases in moist conditions with mobile or nonmobile water film. A mobile water film, however, compensates its negative effect up to 50% by enhancing gas flow compared with static water molecules. The real gas flow is dominated by the gas slippage and water film mobility which are dependent upon pore-scale parameters such as pore sizes, topology, pressure, and surface wettability. Compared with inorganic pores, gas transport in organic pores is greatly enhanced by the water film flow due to the strong water slip. Moreover, the contribution of water film mobility is remarkable in small pores with large contact angles, especially at high pressures. At moist conditions, the real gas effect enhances gas flow by improving both gas slippage and water film mobility, which is more prominent in smaller pores at high pressures. The presented model and its results will further advance our understanding of the mechanisms responsible for the water and gas transport in nanoporous media, and consequently, the hydrocarbon exploration of shale reservoirs.

A New Unified Gas-Transport Model for Gas Flow in Nanoscale Porous Media

SPE Journal ◽  
2019 ◽  
Vol 24 (02) ◽  
pp. 698-719 ◽  
Author(s):  
Di Chai ◽  
Zhaoqi Fan ◽  
Xiaoli Li
Keyword(s):  
Viscous Flow ◽  
Pore Size ◽  
Surface Diffusion ◽  
Gas Flow ◽  
Gas Transport ◽  
Transport Model ◽  
Knudsen Diffusion ◽  
Apparent Permeability ◽  
Real Gas ◽  
Reservoir Conditions

Summary A new unified gas-transport model has been developed to characterize single-component real-gas flow in nanoscale organic and inorganic porous media by modifying the Bravo (2007) model. More specifically, a straight capillary tube is characterized by a conceptual layered model consisting of a viscous-flow zone, a Knudsen-diffusion zone, and a surface-diffusion zone. To specify the contributions of the viscous flow and the Knudsen diffusion to the gas transport, the virtual boundary between the viscous-flow and Knudsen-diffusion zones is first determined using an analytical molecular-kinetics approach. As such, the new unified gas-transport model is derived by integrating the weighted viscous flow and Knudsen diffusion, and coupling surface diffusion. The model is also comprehensively scaled up to the bundles-of-tubes model considering the roughness, rarefaction, and real-gas effect. Nonlinear programming methods have been used to optimize the empirical parameters in the newly proposed gas-transport model. Consequently, the newly proposed gas-transport model yields the most accurate molar fluxes compared with the Bravo (2007) model and four other analytical models. One of the advantages of the new unified gas-transport model is its great flexibility, because the Knudsen number is included as an independent variable, which also endows the newly proposed model with the capability to cover the full-flow regimes. In addition, the apparent permeability has been mathematically derived from the new unified gas-transport model. A series of simulations has been implemented using methane gas. It is found through sensitivity analysis that apparent permeability is strongly dependent on pore size, porosity, and tortuosity, and weakly dependent on the surface-diffusivity coefficient and pore-surface roughness. The increased viscosity can reduce the total molar flux in the inorganic pores up to 66.0% under the typical shale-gas-reservoir conditions. The viscous-flow mechanism cannot be neglected at any pore sizes under reservoir conditions, whereas the Knudsen diffusion is found to be important when pore size is smaller than 2 nm and pressure is less than 35.0 MPa. The contribution of surface diffusion cannot be ignored when the pore size is smaller than 10 nm and the pressure is less than 15.0 MPa.

scholarly journals Approximate Method for Calculating the Pressure Change in a Nonequilibrium-Deformable Reservoir in the Case of Real Gas Flow to the Well

2021 ◽  
Vol 135 (4) ◽  
pp. 36-39
Author(s):  
B. Z. Kazymov ◽  
◽  
K. K. Nasirova ◽  
Keyword(s):  
Approximate Method ◽  
Gas Flow ◽  
Pressure Change ◽  
Reservoir Pressure ◽  
Gas Reservoir ◽  
Real Gas ◽  
The Real ◽  
Over Time

A method is proposed for determining the distribution of reservoir pressure over time in a nonequilibrium-deformable gas reservoir in the case of real gas flow to the well under different technological conditions of well operation, taking into account the real properties of the gas and the reservoir.

scholarly journals Shale gas transport model in 3D fractal porous media with variable pore sizes

2018 ◽  
Vol 98 ◽  
pp. 437-447 ◽  
Author(s):  
Jianchao Cai ◽  
Duanlin Lin ◽  
Harpreet Singh ◽  
Wei Wei ◽  
Shangwen Zhou
Keyword(s):  
Porous Media ◽  
Shale Gas ◽  
Gas Transport ◽  
Transport Model ◽  
Pore Sizes ◽  
Shale Gas Transport

Multiple-flow-regime models for real gas transport in fractal porous media at high pressure

2021 ◽  
Vol 196 ◽  
pp. 107684
Author(s):  
Lan Zhang ◽  
Yingjun Wang ◽  
Ming Liu ◽  
Liquan Wang ◽  
Hengxu Liu
Keyword(s):  
High Pressure ◽  
Porous Media ◽  
Flow Regime ◽  
Gas Transport ◽  
Real Gas

The Use of an r-z Model To Study the Effect of Completion Technique on Gas Well Deliverability

1973 ◽  
Vol 13 (05) ◽  
pp. 259-266
Author(s):  
Henry B. Crichlow ◽  
Paul J. Root
Keyword(s):  
Gas Flow ◽  
Flow Equation ◽  
Coefficient Of Performance ◽  
Gas Wells ◽  
Gas Well ◽  
Real Gas ◽  
The Real ◽  
Fluid Properties ◽  
Set Up ◽  
Gas Potential

Abstract A digital computer model of a radial gas reservoir was constructed to investigate the effect of completion techniques on gas well deliverability. The model was a standard r-z model divided linearly in the z-direction and logarithmically in the r-direction. Individual reservoir properties were assigned to each element of the model grid. These include porosity, radial and vertical permeability, and water saturation. A finite-difference approach was used to set up the flow equations, and both alternating direction implicit procedure (ADIP) and line successive overrelaxation (LSOR) were used to set up the system of simultaneous equations. The Thomas algorithm was used to solve the tridiagonal systems. From this research the following conclusions were drawn:(1)The real gas potential is effective in linearizing the gas flow equation. For nonturbulent flow the coefficient of performance in the backpressure equation, Q = C [ (Pe) - (Pw)]n can be evaluated independently oil the fluid properties of the gas.(2)Partially producing properties of the gas.(2)Partially producing intervals constitute a skin, the magnitude of which depends on the location of the perforations and the anisotropic nature of the medium.(3)In a damaged or stimulated well, within limits, the significant factor in deliverability reduction is the kind rather than the extent of the damage.(4)From the numerical standpoint ADIP is a more efficient method in "well-behaved" problemsthat is, in homogeneous systemswhereas LSOR is better suited to partially open and nonhomogeneous systems. Introduction Calculation of the flow rate and prediction of the deliverability of gas wells are factors of great economic importance to the natural gas industry. Consequently, the accurate analysis of gas flow in producing gas wells has been a subject of considerable interest, and many papers dealing with it may be found in the literature. One of the earliest methods for calculating gas flow, that of Jenkins and Aronofsky, involved the succession of steady states. Janicek and Katz, using a similar assumption that the rate of pressure change with time is independent of the radius at any given time, derived a set of relatively straightforward predictive equations. Other calculational methods are based on solutions to the partial differential equation describing gas flow in a porous medium. Until recently the analysis was based on linearizations that required evaluation of the gas properties at some average pressure. As a result, these solutions can be applied only when the flow gradients are small. Today gas reservoirs are being discovered at much greater depths and at relatively higher pressures. In many cases the formation permeability pressures. In many cases the formation permeability to gas is quite low. Thus, solutions to be linearized equation can lead to serious errors in predicting deliverability (and, hence, reserves) predicting deliverability (and, hence, reserves) because of the large drawdowns occurring in these systems. The simplifying assumptions implied by the linearized equations are not necessary when the real gas potential proposed by Al-Hussainy et al. is used. This function greatly facilitates the incorporation of the pressure-dependent variables, viscosity, and gas deviation factor into a mathematical model of gas flow. Its use reduces the unsteady-state flow equation directly to a form analogous to that of the diffusivity equation without the tacit assumptions that the pressure gradients within the flow system are small. Furthermore, the coefficients of the spatial derivatives no longer contain the pressure-dependent fluid properties. Because of these advantages the (p) function was used in this investigation of gas well deliverability. SPEJ P. 259

scholarly journals A Unified Multiple Transport Mechanism Model for Gas through Shale Pores

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-17
Author(s):  
Fanhui Zeng ◽  
Yu Zhang ◽  
Jianchun Guo ◽  
Wenxi Ren ◽  
Tao Zhang ◽  
...  
Keyword(s):  
Pore Size ◽  
Flow Regime ◽  
Transport Mechanism ◽  
Gas Transport ◽  
Transport Mechanisms ◽  
Real Gas ◽  
The Real ◽  
Mechanism Model ◽  
Entire Flow ◽  
Organic Pores

Predicting apparent gas permeability (AGP) in nanopores is a major challenge for shale gas development. Considering the differences in the gas molecule-pore wall interactions in inorganic and organic nanopores, the gas transport mechanisms in shale remain unclear. In this paper, gas flow channels in shale, which are separated into inorganic pores and organic pores, are treated as nanotubes. Inorganic pores are assumed to be hydrophilic, and organic pores are assumed to be hydrophobic. In organic pores, multiple bulk free gas and surface adsorbed gas transport mechanisms are incorporated, while the bulk gas and water film are considered within inorganic pores. This paper presents a unified multiple transport mechanism model for both organic nanopores and inorganic nanopores. Unlike the earlier models, the presented models consider the absorption, stress dependence, real gas, and water storage effects on gas transport comprehensively for the entire flow regime. The results are validated with published data which is more in line with the real situation. The results show that (1) the AGP decreases gradually as the pore pressure decreases but that the decrease is sharp in small pores, (2) the AGP decreases dramatically when considering the real gas effect at 50 MPa in a 2 nm pore size, and (3) for a small pore size at the critical high-water saturation, AGP might increase suddenly as the flow regime changes from continuum flow to slip flow. The findings of this study can help for better understanding of the gas transport mechanisms for the entire flow regime in shale.

Experimental Study of the Real Gas Flow in Microtubes

2012 ◽  
Vol 496 ◽  
pp. 347-350
Author(s):  
Qing Min Zhao ◽  
Xiang An Yue ◽  
Fei Wang
Keyword(s):  
High Pressure ◽  
Gas Flow ◽  
Flow Characteristics ◽  
Low Pressure ◽  
Real Gas ◽  
The Real ◽  
Gas Seepage ◽  
Theoretical Predictions ◽  
Inner Diameter ◽  
Microscale Effect

The flow characteristics of nitrogen in microtubes with diameters of 14.9, 10.1, 5.03 and 2.05μm are investigated experimentally under high pressure conditions. The results show that the high pressure flow characteristics of nitrogen in microtube with the diameter of 14.9μm are in accordance with the classical fluid mechanics theory. However, with the decrease of the inner diameter of microtube, gas flow shows an apparent microscale effect and the results depart from the theoretical predictions of the conventional theory, moreover the smaller the diameter, the stronger the microscale effect. Besides, the high pressure microscale effect can not be characterized by the Knudsen number, which is proposed for studying rarefaction effect at low-pressure. Because of the existence of high-pressure microscale effect, it is inappropriate to study the real gas seepage characteristic in reservoir through the flow experiment at low pressure.

scholarly journals Direct Numerical Simulation of Real-gas Effects within Turbulent Boundary Layers for Fully-developed Channel Flows

2021 ◽  
Vol 5 ◽  
pp. 216-232
Author(s):  
Tao Chen ◽  
Bijie Yang ◽  
Miles Robertson ◽  
Ricardo Martinez-Botas
Keyword(s):  
Outer Layer ◽  
Gas Flow ◽  
Reynolds Shear Stress ◽  
Turbulent Viscosity ◽  
Spanwise Direction ◽  
Real Gas ◽  
The Real ◽  
Real Gas Effect ◽  
Real Gas Effects ◽  
Gas Effect

Real-gas effects have a significant impact on compressible turbulent flows of dense gases, especially when flow properties are in proximity of the saturation line and/or the thermodynamic critical point. Understanding of these effects is key for the analysis and improvement of performance for many industrial components, including expanders and heat exchangers in organic Rankine cycle systems. This work analyzes the real-gas effect on the turbulent boundary layer of fully developed channel flow of two organic gases, R1233zd(E) and MDM - two candidate working fluids for ORC systems. Compressible direct numerical simulations (DNS) with real-gas equations of state are used in this research. Three cases are set up for each organic vapour, representing thermodynamic states far from, close to and inside the supercritical region, and these cases refer to weak, normal and strong real-gas effect in each fluid. The results within this work show that the real-gas effect can significantly influence the profile of averaged thermodynamic properties, relative to an air baseline case. This effect has a reverse impact on the distribution of averaged temperature and density. As the real-gas effect gets stronger, the averaged centre-to-wall temperature ratio decreases but the density drop increases. In a strong real-gas effect case, the dynamic viscosity at the channel center point can be lower than at channel wall. This phenomenon can not be found in a perfect gas flow. The real-gas effect increases the normal Reynolds stress in the wall-normal direction by 7–20% and in the spanwise direction by 10–21%, which is caused by its impact on the viscosity profile. It also increases the Reynolds shear stress by 5–8%. The real-gas effect increases the turbulence kinetic energy dissipation in the viscous sublayer and buffer sublayer <inline-formula><mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" display="inline" overflow="scroll"><mml:mo stretchy="false">(</mml:mo><mml:msup><mml:mi>y</mml:mi><mml:mo>∗</mml:mo></mml:msup><mml:mo><</mml:mo><mml:mn>30</mml:mn><mml:mo stretchy="false">)</mml:mo></mml:math></inline-formula> but not in the outer layer. The turbulent viscosity hypthesis is checked in these two fluids, and the result shows that the standard two-function RANS model (<inline-formula><mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" display="inline" overflow="scroll"><mml:mi>k</mml:mi><mml:mo>−</mml:mo><mml:mi>ϵ</mml:mi></mml:math></inline-formula> and <inline-formula><mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" display="inline" overflow="scroll"><mml:mi>k</mml:mi><mml:mo>−</mml:mo><mml:mi>ω</mml:mi></mml:math></inline-formula>) with a constant <inline-formula><mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" display="inline" overflow="scroll"><mml:msub><mml:mi>C</mml:mi><mml:mi>μ</mml:mi></mml:msub><mml:mo>=</mml:mo><mml:mn>0.09</mml:mn></mml:math></inline-formula> is still suitable in the outer layer <inline-formula><mml:math xmlns:mml="http://www.w3.org/1998/Math/MathML" display="inline" overflow="scroll"><mml:mo stretchy="false">(</mml:mo><mml:msup><mml:mi>y</mml:mi><mml:mo>∗</mml:mo></mml:msup><mml:mo>></mml:mo><mml:mn>70</mml:mn><mml:mo stretchy="false">)</mml:mo></mml:math></inline-formula>, with an error in ±10%.

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