Reservoir Simulation of Shale Gas in the Slip Flow Regime (original) (raw)
Related papers
Modeling and Simulation of Natural Gas Production from Unconventional Shale Reservoirs
Modeling and simulation of unconventional reservoirs are much more complicated than the conventional reservoir modeling, because of their complex flow characteristics. Mechanisms, which control the flow in the reservoir, are still under the investigation of researchers. However, it is important to investigate applications of mechanisms which are present to our knowledge. This paper presents the theory and applications of flow mechanisms in unconventional reservoir modeling. It is a well-known fact that most of the reservoir flow problems are non-linear due to pressure dependency of particular parameters. It is also widely accepted that fully numerical solutions are costly both computational and time wise. Therefore, the presented model in this paper follows semi-analytical solution methods. Gas adsorption in unconventional reservoirs is the major pressure dependent mechanism; in addition existence of natural fractures is also taken considerable attention. This paper aims to investigate combined effect of existence of natural fractures gas adsorption, and gas slippage effect while keeping the computational effort in acceptable range. Unlike the existing literature (Langmuir is widely used), BET multi-layer isotherm employed in this paper for gas adsorption modeling. A modified dual porosity modeling is used for natural fracture and gas slippage effect modeling. For model verification purposes a history matched is performed with real field data from Marcellus shale. The proposed model in this paper shows a good agreement with the field data. It is observed that BET isotherm models early time production performance more accurately than Langmuir isotherm. It is also concluded that gas adsorption significantly improves the production performances of unconventional reservoirs, with natural fractures. In addition, gas slippage has a slight effect in long term production.
North American Unconventional Gas Conference and Exhibition, 2011
We combine a new pore-scale model with a reservoir simulation algorithm to predict gas production in gas-bearing shales. It includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. The pore-scale model quantifies macroscopic petrophysical properties of formations using an algorithm of gas transport in porous media that simultaneously considers the effects of no-slip and slip flow, Knudsen diffusion, and Langmuir desorption. Subsequently, the reservoir model populates petrophysical properties derived from the pore-scale analysis at every numerical grid and at each time-step to calculate the production history and pressure distribution in the reservoir. This approach examines the contribution of different transport processes (i.e. advective flow, Knudsen diffusion, and desorption) to quantify their corresponding contributions to overall flow. Previously, we showed that slip flow and Knudsen diffusion p...
Production Analysis of Tight-Gas and Shale-Gas Reservoirs Using the Dynamic-Slippage Concept
Spe Journal, 2012
Shales and some tight-gas reservoirs have complex, multimodal pore-size distributions, including pore sizes in the nanopore range, causing gas to be transported by multiple flow mechanisms through the pore structure. Ertekin et al. (1986) developed a method to account for dual-mechanism (pressure-and concentration-driven) flow for tight formations that incorporated an apparent Klinkenberg gas-slippage factor that is not a constant, which is commonly assumed for tight gas reservoirs. In this work, we extend the dynamic-slippage concept to shale-gas reservoirs, for which it is postulated that multimechanism flow can occur. Inspired by recent studies that have demonstrated the complex pore structure of shalegas reservoirs, which may include nanoporosity in kerogen, we first develop a numerical model that accounts for multimechanism flow in the inorganic-and organic-matter framework using the dynamicslippage concept. In this formulation, unsteady-state desorption of gas from the kerogen is accounted for. We then generate a series of production forecasts using the numerical model to demonstrate the consequences of not rigorously accounting for multimechanism flow in tight formations. Finally, we modify modern rate-transient-analysis methods by altering pseudovariables to include dynamic-slippage and desorption effects and demonstrate the utility of this approach with simulated and field cases. The primary contribution of this work is therefore the demonstration of the use of modern rate-transientanalysis methods for reservoirs exhibiting multimechanism (non-Darcy) flow. The approach is considered to be useful for analysis of production data from shale-gas and tight-gas formations because it captures the physics of flow in such formations realistically.
… Gas Conference and …, 2011
We combine a new pore-scale model with a reservoir simulation algorithm to predict gas production in gas-bearing shales. It includes an iterative verification method of surface mass balance to ensure real-time desorption-adsorption equilibrium with gas production. The pore-scale model quantifies macroscopic petrophysical properties of formations using an algorithm of gas transport in porous media that simultaneously considers the effects of no-slip and slip flow, Knudsen diffusion, and Langmuir desorption. Subsequently, the reservoir model populates petrophysical properties derived from the pore-scale analysis at every numerical grid and at each time-step to calculate the production history and pressure distribution in the reservoir. This approach examines the contribution of different transport processes (i.e. advective flow, Knudsen diffusion, and desorption) to quantify their corresponding contributions to overall flow. Previously, we showed that slip flow and Knudsen diffusion play a significant role in explaining the higher-than-expected permeability observed in shale-gas formations with pore-throat sizes in the range of nanometers. It is shown that Langmuir desorption from organic-matter surfaces is important in the calculation of stored gas in gas-bearing shales. Modeling results show that gas desorption maintains the reservoir pressure via the supply of gas. In comparison to conventional reservoir descriptions, the contributions of slip flow and Knudsen diffusion increase the apparent permeability of the reservoir while gas production takes place. The effects of both mechanisms explain the higher-than-expected gas production rates commonly observed in these formations.
Modeling and simulation of gas flow behavior in shale reservoirs
Journal of Petroleum Exploration and Production Technology
Shale is a growing prospect in this world with decreasing conventional sources of fossil fuel. With the growth in demand for natural gas, there is impending need for the development of the robust model for the flow of shale gas (Behar and Vandenbroucke in Org Geochem, 11:15-24, 1987). So the major driving force behind the working on this major project is the unavailability of desired models that could lead to enhanced production of these wells and that too efficiently. This model mainly includes the movement of shale gas from tight reservoir through the conductive fractures to wellbore and production model of the decline in pressure inside the reservoir with respect to time. This result has been further compared with the help of MATLAB so as to obtain a complete pressure-derived model. The result shows the applicability of this in the real-life projects where it is difficult to model the fractures and obtain the flow rate with them in fractures and how to set the production facilities becomes a question.
Key Factors in Shale Gas Modeling and Simulation
Archives of Mining Sciences, 2014
Multi-stage hydraulic fracturing is the method for unlocking shale gas resources and maximizing horizontal well performance. Modeling the effects of stimulation and fluid flow in a medium with extremely low permeability is significantly different from modeling conventional deposits. Due to the complexity of the subject, a significant number of parameters can affect the production performance. For a better understanding of the specifics of unconventional resources it is necessary to determine the effect of various parameters on the gas production process and identification of parameters of major importance. As a result, it may help in designing more effective way to provide gas resources from shale rocks. Within the framework of this study a sensitivity analysis of the numerical model of shale gas reservoir, built based on the latest solutions used in industrial reservoir simulators, was performed. The impact of different reservoir and hydraulic fractures parameters on a horizontal s...
Modeling Gas Transport in Shale Reservoir – Conservation Laws Revisited
Transport of gas in a shale reservoir may be greatly different from that in a conventional reservoir. This is primarily due to shale's small pore size, extremely-low permeability and presence of adsorbed gas. It is also because the low permeability formation matrix is intervened with highly conductive hydraulic fractures. Although some of the involved mechanisms such as gas molecule slippage (Klingenberg effect) and non-Darcy flow (Forchheimer effect) have been extensively studied since early pioneering works decades ago, there is still a need for improved fundamental understanding and proper quantification. This paper clarifies some of the confusions floating around the topic of non-Darcy gas flow. A comprehensive model of gas transport in shale reservoirs, including contributions due to gas molecule slippage, inertial forces and gas desorption is constructed directly from the fundamental laws of mass, momentum and energy conservation. The model is then applied to simulate production from hydraulically fractured shale gas reservoirs.
Numerical Simulation of Natural Gas Flow in Anisotropic Shale Reservoirs
Shale gas resources have received great attention in the last decade due to the decline of the conventional gas resources. Unlike conventional gas reservoirs, the gas flow in shale formations involves complex processes with many mechanisms such as Knudsen diffusion, slip flow (Klinkenberg effect), gas adsorption and desorption, strong rock-fluid interaction, etc. Shale formations are characterized by the tiny porosity and extremely low-permeability such that the Darcy equation may no longer be valid. Therefore, the Darcy equation needs to be revised through the permeability factor by introducing the apparent permeability. With respect to the rock formations, several studies have shown the existence of anisotropy in shale reservoirs, which is an essential feature that has been established as a consequence of the different geological processes over long period of time. Anisotropy of hydraulic properties of subsurface rock formations plays a significant role in dictating the direction of fluid flow. The direction of fluid flow is not only dependent on the direction of pressure gradient, but it also depends on the principal directions of anisotropy. Therefore, it is very important to take into consideration anisotropy when modeling gas flow in shale reservoirs. In this work, the gas flow mechanisms as mentioned earlier together with anisotropy are incorporated into the dual-porosity dual-permeability model through the full-tensor apparent permeability. We employ the multipoint flux approximation (MPFA) method to handle the full-tensor apparent permeability. We combine MPFA method with the experimenting pressure field approach, i.e., a newly developed technique that enables us to solve the global problem by breaking it into a multitude of local problems. This approach generates a set of predefined pressure fields in the solution domain in such a way that the undetermined coefficients are calculated from these pressure fields. In other words, the matrix of coefficients is constructed automatically within the solver. We ran a numerical model with different scenarios of anisotropy orientations and compared the results with the isotropic model in order to show the differences between them. We investigated the effect of anisotropy in both the matrix and fracture systems. The numerical results show anisotropy plays a crucial role in dictating the pressure fields as well as the gas flow streamlines. Furthermore, the numerical results clearly show the effects of anisotropy on the production rate and cumulative production. Incorporating anisotropy together with gas flow mechanisms in shale formations into the reservoir model is essential particularly for predicting maximum gas production from shale reservoirs.
Finite Volume Method for Modelling Gas Flow in Shale
ECMOR XIV - 14th European conference on the mathematics of oil recovery, 2014
Gas flow in shale is a complex phenomenon and is currently being investigated using a variety of modelling and experimental approaches. A range of flow mechanisms need to be taken into account when describing gas flow in shale including continuum, slip, transitional flow and Knudsen diffusion. A finite volume method (FVM) is presented to mathematically model these flow mechanisms. The approach incorporates the Knudsen number as well as the gas adsorption isotherm, allowing different flow mechanisms to be taken into account as well as methane sorption on organic matter. The approach is applicable to non-linear diffusion problems, in which the permeability and fluid density both depend on the scalar variable, the pressure. The FVM is fully conservative, as it obeys exact conservation laws in a discrete sense integrated over finite volumes. The method is validated first on unsteady-state problems for which analytical or numerical solutions are available. The approach is then applied for solving pressurepulse decay tests and a comparison with an alternative finite element numerical solution is made. Results for practical laboratory pressure-pulse decay tests of samples with very low permeability are also presented.
Some key technical issues in modelling of gas transport process in shales: a review
Geomechanics and Geophysics for Geo-Energy and Geo-Resources, 2016
As a result of small pore sizes and property heterogeneities at different scales, flow processes and the related physical mechanisms in shales can be dramatically different from those in conventional gas reservoirs. To accurately capture the ''unconventional'' flow and transport in shales requires reevaluation of dominant physics controlling flow in shales, as well as innovative hardware technologies to estimate critical material and flow properties. To do so, we need to quantify the current knowledge and identify technology gaps especially as related to the modeling fluid flow in shale gas reservoirs. While fluid flow in shale includes many important aspects, this paper focuses on fluid flow in complex heterogeneous shale matrix. It discusses the recent progress in the areas of multiscale fluid flow, fracturing fluid imbibition, and stressdependent shale matrix properties. Future research topics in the related areas are also suggested based on the identified technology gaps.