Effects of non-Darcy flow and pore proximity on gas condensate production from nanopore unconventional resources (original) (raw)
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SPE Unconventional Resources Conference, 2014
Transport properties and mechanisms as well as phase behavior under nanoscale confinement exhibit significant deviations from their bulk behavior. This is due to the significant effect of molecule-wall interactions as well as molecule-molecule interactions in shale formations which are mainly characterized by nanopores. Consequently, production from shale gas reservoirs is strongly influenced by pore sizes and their effects on phase behavior and transport properties. In this study, we focus on analyzing and determining the effect of phase behavior and transport properties change due to pore proximity on production from a shale gas condensate reservoir. Additionally, the effect of different connectivities between pore sizes on production is studied. The effect of pore size on phase behavior is considered by using modified critical properties for different pore sizes in the phase behavior calculations. A shale gas condensate reservoir with a ternary mixture of methane (80 mol%), n-butane (10 mol%), and n-octane (10 mol%) as the reservoir fluid is modeled. The reservoir pressure and temperature are 5000 psia and 180 °F, respectively. The dew point pressure is 3600 psia. Pore sizes change between 5-150nm. Based on Scanning Electron Microscopy (SEM) studies on shale reservoir rocks, the pore volume of the reservoir was divided into five regions: bulk (stimulated area and pore sizes more than 50nm (17% PV)), 20-50nm (4% of PV), 15-20nm (6% of PV), 10-15nm (45% of PV), and less than 10nm (28% of PV). Three different types of connectivities between pores were considered: 1-completely random distribution 2-pore sizes from smallest to largest connected to the SRV in series, and 3-pore sizes from largest to smallest connected to the SRV in series. Our study has shown that by decreasing the pore size, dew point pressures decrease between 5 to 17%. Also by decreasing pore size, two-phase region shrinks therefore condensate drop-out and near wellbore permeability impairment are reduced. After 10 years of production, condensate saturation around SRV is 6-10% less under confinement effects. Gas and condensate viscosities under confinement decrease 3-16% and 10-45% respectively. Considering effect of confinement did not affect gas production significantly but the liquid production increased significantly and doubled. The effect of different pore size connectivities caused a 20% change in liquid productions. The results of this study can have a significant impact on our understanding of gas condensation and transport in shale formations thereby enabling improved field planning, well placement, completions design and facilities management.
Gas-condensate flow modelling for shale reservoirs
Journal of Natural Gas Science and Engineering, 2018
Condensate banking is the most challenging engineering problem in the development of gas-condensate reservoirs where the condensate accumulation can dramatically reduce the gas permeability resulting in impairment of wells productivity. An accurate assessment of condensate banking effect is important to predict well productivity and to diagnose well performance. Traditionally, Darcy law, combined with relative permeability models, has been used for modelling condensate banking effect in conventional reservoirs. This approach is also widely adopted in reservoir engineering commercial tools. However, for shale gas-condensate reservoirs, the gas flow deviates from Darcy flow to Knudsen flow due to the very small pore size in shale matrix (3-300 nm), compared to conventional reservoirs (10-200 µm). This gas flow is highly dependent on pore size distribution and reservoir pressure. In this paper, the effect of condensate saturation on Knudsen flow in shale matrix kerogen is investigated using a 3D pore network with a random pore size distribution. The Knudsen flow is incorporated at the pore level and gas permeability is evaluated for the whole network. In addition, the pore distribution effect in terms of log-normal mean and standard deviation is investigated. The concept of relative permeability in Darcy flow is extended to Knudsen flow by defining a new parameter called relative correction factor to evaluate the effect of condensate banking on Knudsen flow. This parameter can be employed directly in reservoir engineering tools. Simulation results showed that the relative correction factor is not only dependent on condensate saturation but also on pressure. This is due to the impact of pressure on the contribution of pore size ranges into the gas flow. In addition, results showed the effect of the pore size distribution where the standard deviation controls mainly the behaviour of Knudsen flow under condensate saturation. Disregarding this effect can lead to an overestimation of Knudsen flow contribution in well production under condensate banking effect.
Mehran University Research Journal of Engineering and Technology, 2018
Four core samples of outcrop type shale from Mancos, Marcellus, Eagle Ford, and Barnett shale formations were studied to evaluate the productivity performance and reservoir connectivity at elevated temperature and pressure. These laboratory experiments were conducted using hydrostatic permeability system with helium as test gas primarily to avoid potential significant effects of adsorption and/or associated swelling that might affect permeability. It was found that the permeability reduction was observed due to increasing confining stress and permeability improvement was observed related to Knudsen flow and molecular slippage related to Klinkenberg effect. Through the effective permeability of rock is improved at lower pore pressures, as 1000 psi. The effective stress with relatively high flow path was identified, as 100-200 nm, in Eagle Ford core sample. However other three samples showed low marginal flow paths in low connectivity.
Gas Multiple Flow Mechanisms and Apparent Permeability Evaluation in Shale Reservoirs
Sustainability, 2019
Gas flow mechanisms and apparent permeability are important factors for predicating gas production in shale reservoirs. In this study, an apparent permeability model for describing gas multiple flow mechanisms in nanopores is developed and incorporated into the COMSOL solver. In addition, a dynamic permeability equation is proposed to analyze the effects of matrix shrinkage and stress sensitivity. The results indicate that pore size enlargement increases gas seepage capacity of a shale reservoir. Compared to conventional reservoirs, the ratio of apparent permeability to Darcy permeability is higher by about 1–2 orders of magnitude in small pores (1–10 nm) and at low pressures (0–5 MPa) due to multiple flow mechanisms. Flow mechanisms mainly include surface diffusion, Knudsen diffusion, and skip flow. Its weight is affected by pore size, reservoir pressure, and temperature, especially pore size ranging from 1 nm to 5 nm and reservoir pressures below 5 MPa. The combined effects of mat...
Gas transport and storage capacity in shale gas reservoirs – A review. Part A: Transport processes
Journal of Unconventional Oil and Gas Resources, 2015
For decades, scientists and engineers have been investigating and describing storage and transport mechanisms in geological porous media such as reservoir rocks. This effort has resulted in the development of concepts such as single-phase and multi-phase flow, which describe the storage and transport of fluids in conventional reservoir rock types such as sandstones and carbonates. However, many of these concepts are not directly applicable to unconventional reservoirs. For example, shale gas reservoirs consist of organic-rich lithotypes, which have high compressibility, very small pore throats, low porosities and extremely low and anisotropic permeabilities, and relatively low gas storage capacities. The models developed to describe conventional reservoirs do not accurately describe the hydrocarbon transport processes involved in these rocks. In this part A of the review paper, we aim to provide a concise and complete review on characterizing the fluid transport processes in unconventional reservoirs. We will examine processes occurring at various spatial scales, ranging from fracture flow on the centimeter scale down to slip-flow on the nanometer scale. Due to the softer nature of tight shales, many processes, such as slip-flow and the pore-throat compressibility, will have to be considered as coupled. We also develop a detailed description of the coupling between slip-flow, which is a fluid dynamic effect, and the pore-throat compressibility, which is a poroelastic effect, in unconventional reservoirs, and interpret experimental observations in light of this description. Furthermore, we discuss in detail how these transport properties depend on organic content, clay content and type, amount of pre-adsorbed water and pore compressibility.
Numerical investigation of gas flow rate in shale gas reservoirs with nanoporous media
International Journal of Heat and Mass Transfer, 2015
Theoretical analysis of transport mechanism of gas flow in shale gas reservoirs with nanoporous media was carried out on the basis of molecular kinetic theory. The motion equation and mathematical model of shale gas transport in multi-scale medium are established in this article. The pressure distribution equation of radial flow was derived, and the computing method of the control area of gas well was presented. Additionally, the volume flow rate equations of vertical and horizontal fractured wells were obtained. Through Newton iterative method, volume flow rate was analyzed, considering various factors such as production pressure drawdown, fracture half-length, fracture conductivity, fracture spacing and diffusion coefficient. According to the numerical results, the volume flow rate of the gas well increases when the diffusion coefficient grows. Consequently diffusion in shale gas reservoirs with nanoporous media plays an important role. With increase of fracture half-length, the volume flow rate increases first and then tends towards stability. Moreover, for certain length of the horizontal wellbore, when fracture spacing increases and the number of the fractures lessens, the control area and the volume flow rate of the gas well decreases. Therefore, there is an optimum allocation among these factors to achieve maximum volume flow.
Analytical models for gas production in a shale reservoir: A review focusing on pore network system
Journal of the Pakistan Institute of Chemical Engineers
Shale gas reservoirs may contain pores with different origins (; natural or induced) and scales. They can be divided into four groups, inorganic porosity, organic porosity, natural micro-fractures porosity and artificially created fractures porosity. The inorganic porosity is the void spaces within matrix of clay, pyrite, silica and other non-organic minerals. The organic porosity is the void space that remains in organic matter after conversion the kerogen to gas and oil. Organic matter in the form of kerogen is finely dispersed within inorganic matrix and contain void spaces (organic porosity). Micro-fractures network contains void spaces (natural micro-fractures porosity) and pore network system is also formed after creation of hydraulically induced fractures (artificially created fractures porosity). Simulating gas production from shale gas is a complex process due to interaction of fluid with various pore scales. In the current research work, shale gas transport through complex...
Pore-scale analysis of gas injection in gas-condensate reservoirs
Journal of Petroleum Science and Engineering, 2022
Condensate banking around wellbores can significantly shorten the production from gas-condensate reservoirs. Different approaches to mitigate this issue have been proposed in the literature, among which gas injection comes out with promising results. With this method, pressure maintenance and condensate re-vaporization can be achieved, lessening the flow blockage caused by liquid dropout and accumulation in the porous medium. While gas injection in gas-condensate reservoirs has been largely investigated at the meso and macro scales, data regarding the method's efficiency at the micro scale are scarce. Therefore, the effects of local changes in gas and condensate properties stemmed from the interaction between injected and reservoir fluids at the pore-scale are poorly understood. In order to evaluate how these changes affect the transport in porous media, a compositional pore-network model was used to reproduce gas injection in a sandstone sample following condensate accumulation. C 1 , C 2 , CO 2 , N 2 and produced gas were tested as the candidates for condensate banking remediation at different pressure levels. After gas flooding, condensate saturation, heavy component recovery and gas relative permeability were quantified to appraise the achieved gas flow improvement. The results indicated that C 2 and CO 2 were the most effective gases to clear the accumulated condensate and re-establish the gas flow. Conversely, C 1 and N 2 , especially mixed with the produced fluids, displayed the least favorable results, and could even lead to gas flow impairment.
SPE Unconventional Resources Conference, 2014
A practical simulation model is developed and demonstrated with applications for accurate characterization of production rate and pressure behavior with time in shale-gas reservoirs featuring horizontal wells intersected with multi-stages of hydraulic fractures. The model determines the contribution of each fracture stage to the overall production and predicts the pressure changes occurring in the fracture and matrix zones by a compartmental simulation approach. Various flow regimes of drawdown test are investigated for fracture diagnosis with different fracture permeability values to determine the external boundary effect. Our practical mathematical modeling, coupling the wellbore and reservoir hydraulics, is solved numerically by an iterative method to determine the flow rates coming into the horizontal well from multiple hydraulic fractures like the commingled layers intersected by a vertical well. This approach provides a reasonable description of behavior of multiple stages in shale gas reservoirs by considering the alteration of the gas transport properties and the changing apparent permeability under the effect of pore proximity of shale. Various applications of our non-Darcy simulation model demonstrate the importance of the corrections relevant for shale-gas reservoirs compared with the conventional Darcy flow without consideration of such corrections. Commensurate with field observations, when the non-Darcy flow corrections are considered, the cumulative gas production is higher compared with the conventional Darcy flow calculations which impact significantly on fracture and matrix pressure responses and production forecasting.