scholarly journals Triple-Porosity Modelling for the Simulation of Multiscale Flow Mechanisms in Shale Reservoirs

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-11 ◽  
Author(s):  
Mingyao Wei ◽  
Jishan Liu ◽  
Derek Elsworth ◽  
Enyuan Wang
Keyword(s):  
Shale Gas ◽  
History Matching ◽  
Gas Transport ◽  
Gas Production ◽  
Natural Fracture ◽  
System Matrix ◽  
Fracture Permeability ◽  
Gas Reservoir ◽  
Apparent Permeability ◽  
Shale Reservoir

Shale gas reservoir is a typical type of unconventional gas reservoir, primarily because of the complex flow mechanism from nanoscale to macroscale. A triple-porosity model (M3 model) comprising kerogen system, matrix system, and natural fracture system was presented to describe the multispace scale, multitime scale, and multiphysics characteristic of gas flows in shale reservoir. Apparent permeability model for real gas transport in nanopores, which covers flow regime effect and geomechanical effect, was used to address multiscale flow in shale matrix. This paper aims at quantifying the shale gas in different scales and its sequence in the process of gas production. The model results used for history matching also showed consistency against gas production data from the Barnett Shale. It also revealed the multispace scale process of gas production from a single well, which is supplied by gas transport from natural fracture, matrix, and kerogen sequentially. Sensitivity analysis on the contributions of shale reservoir permeability in different scales gives some insight as to their importance. Simulated results showed that free gas in matrix contributes to the main source of gas production, while the performance of a gas shale well is strongly determined by the natural fracture permeability.

A New Method of Optimization Design of Hydraulic Fracture Parameters in Low Porosity and Fractured Gas Reservoir

2013 ◽  
Vol 380-384 ◽  
pp. 1656-1659
Author(s):  
Xiu Ling Han ◽  
Fu Jian Zhou ◽  
Chun Ming Xiong ◽  
Xiong Fei Liu ◽  
Xian You Yang
Keyword(s):  
Simulation Model ◽  
Hydraulic Fracture ◽  
Optimization Design ◽  
Outer Part ◽  
Gas Production ◽  
Natural Fracture ◽  
Fracture Permeability ◽  
Gas Reservoir ◽  
Fracture Conductivity ◽  
High Production Rate

A new composite reservoir simulation model of lower computation cost was used to optimize hydraulic fracture length and fracture conductivity during performing a hydraulic fracturing. The simulation model is divided into inner part and outer part. The inner part is dual-porosity and dual-permeability system, and the other is single porosity system. The research shows that the natural fracture permeability and density are the most influential parameters; a relative long fracture with high hydraulic fracture conductivity is required for a high production rate due to non-Darcy flow effects. A shorter primary fracture is better in a gas reservoir of high natural density. The composite model represents the flow characteristic more accurately and provides the optimal design of fracturing treatments to obtain an economic gas production.

Understanding Shale Gas Flow Behavior Using Numerical Simulation

SPE Journal ◽  
2015 ◽  
Vol 20 (01) ◽  
pp. 142-154 ◽  
Author(s):  
Hao Sun ◽  
Adwait Chawathé ◽  
Hussein Hoteit ◽  
Xundan Shi ◽  
Lin Li
Keyword(s):  
Mass Transfer ◽  
Organic Matter ◽  
Shale Gas ◽  
Inorganic Material ◽  
Gas Transport ◽  
Knudsen Diffusion ◽  
Gas Production ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
Flow Mechanisms

Summary Shale gas has changed the energy equation around the world, and its impact has been especially profound in the United States. It is now generally agreed that the fabric of shale systems comprises primarily organic matter, inorganic material, and natural fractures. However, the underlying flow mechanisms through these multiporosity and multipermeability systems are poorly understood. For instance, debate still exists about the predominant transport mechanism (diffusion, convection, and desorption), as well as the flow interactions between organic matter, inorganic matter, and fractures. Furthermore, balancing the computational burden of precisely modeling the gas transport through the pores vs. running full reservoir scale simulation is also contested. To that end, commercial reservoir simulators are developing new shale gas options, but some, for expediency, rely on simplification of existing data structures and/or flow mechanisms. We present here the development of a comprehensive multimechanistic (desorption, diffusion, and convection), multiporosity (organic materials, inorganic materials, and fractures), and multipermeability model that uses experimentally determined shale organic and inorganic material properties to predict shale gas reservoir performance. Our multimechanistic model takes into account gas transport caused by both pressure driven convection and concentration driven diffusion. The model accounts for all the important processes occurring in shale systems, including desorption of multicomponent gas from the organics' surface, multimechanistic organic/inorganic material mass transfer, multimechanistic inorganic material/fracture network mass transfer, and production from a hydraulically fractured wellbore. Our results show that a dual porosity, dual permeability (DPDP) model with Knudsen diffusion is generally adequate to model shale gas reservoir production. Adsorption can make significant contributions to original gas in place, but is not important to gas production because of adsorption equilibrium. By comparing triple porosity, dual permeability; DPDP; and single porosity, single permeability formulations under similar conditions, we show that Knudsen diffusion is a key mechanism and should not be ignored under low matrix pressure (Pematrix) cases, whereas molecular diffusion is negligible in shale dry gas production. We also guide the design of fractures by analyzing flow rate limiting steps. This work provides a basis for long term shale gas production analysis and also helps define value adding laboratory measurements.

Coupled Hydro-Mechanical Analysis of Gas Production in Fractured Shale Reservoir by Random Fracture Network Modeling

2019 ◽  
Vol 11 (03) ◽  
pp. 1950031
Author(s):  
Rui Yang ◽  
Tianran Ma ◽  
Weiqun Liu ◽  
Yijiao Fang ◽  
Luyi Xing
Keyword(s):  
Network Model ◽  
Shale Gas ◽  
Fracture Network ◽  
Gas Production ◽  
Gas Reservoir ◽  
Secondary Fracture ◽  
Shale Gas Reservoir ◽  
Main Fracture ◽  
Shale Reservoir ◽  
Random Fracture

Accurate construction of a shale-reservoir fracture network is a prerequisite for optimizing the fracturing methods and determining shale-gas extraction schemes. Considering the influence of geological conditions, stress levels, desorption–adsorption, and fissure characteristics and distribution, establishing a shale-gas reservoir fracture-network model based on a random fracture network is significant. According to the discrete network model and Monte Carlo stochastic theory, the random fracture network of natural and artificial fractures in a shale-gas reservoir stimulation zone was constructed in this study. The porosity and permeability of the stimulation zone were calculated according to the network geometric properties. The fracture network was reconstructed, and the fissure connectivity was characterized. Numerical simulation of the seepage flow was performed for shale-gas reservoirs with different fracking-fracture combinations. The results showed that the local permeability dominated by the main fracture was the main factor that affected the initial shale-gas production efficiency. The total shale-gas productivity was mainly controlled by the effective stimulated volume. The evenly distributed secondary fracture network could effectively improve the effective stimulated volume of the stimulation zone. A 4% increase in the effective stimulated volume could improve the accumulated gas production by approximately 12%. Moreover, when the ratio of the main fracture to the secondary fracture was approximately 1:14, the accumulated gas production was optimized.

scholarly journals Analysis of the Influencing Factors on the Well Performance in Shale Gas Reservoir

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-12 ◽  
Author(s):  
Cheng Dai ◽  
Liang Xue ◽  
Weihong Wang ◽  
Xiang Li
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Gas Production ◽  
Recovery Factor ◽  
Natural Fracture ◽  
Total Production ◽  
Gas Reservoir ◽  
Free Gas ◽  
Shale Gas Reservoir ◽  
Adsorbed Gas

Due to the ultralow permeability of shale gas reservoirs, stimulating the reservoir formation by using hydraulic fracturing technique and horizontal well is required to create the pathway of gas flow so that the shale gas can be recovered in an economically viable manner. The hydraulic fractured formations can be divided into two regions, stimulated reservoir volume (SRV) region and non-SRV region, and the produced shale gas may exist as free gas or adsorbed gas under the initial formation condition. Investigating the recovery factor of different types of shale gas in different region may assist us to make more reasonable development strategies. In this paper, we build a numerical simulation model, which has the ability to take the unique shale gas flow mechanisms into account, to quantitatively describe the gas production characteristics in each region based on the field data collected from a shale gas reservoir in Sichuan Basin in China. The contribution of the free gas and adsorbed gas to the total production is analyzed dynamically through the entire life of the shale gas production by adopting a component subdivision method. The effects of the key reservoir properties, such as shale matrix, secondary natural fracture network, and primary hydraulic fractures, on the recovery factor are also investigated.

NANOSCALE PORE SIZE DISTRIBUTION EFFECTS ON GAS PRODUCTION FROM FRACTAL SHALE ROCKS

Fractals ◽  
2019 ◽  
Vol 27 (08) ◽  
pp. 1950142
Author(s):  
JINZE XU ◽  
KELIU WU ◽  
RAN LI ◽  
ZANDONG LI ◽  
JING LI ◽  
...  
Keyword(s):  
Fractal Dimension ◽  
Pore Size Distribution ◽  
Pore Size ◽  
Size Distribution ◽  
Gas Transport ◽  
Gas Production ◽  
Lower Sensitivity ◽  
Apparent Permeability ◽  
Transport Efficiency ◽  
Nanoscale Pore

Effect of nanoscale pore size distribution (PSD) on shale gas production is one of the challenges to be addressed by the industry. An improved approach to study multi-scale real gas transport in fractal shale rocks is proposed to bridge nanoscale PSD and gas filed production. This approach is well validated with field tests. Results indicate the gas production is underestimated without considering a nanoscale PSD. A PSD with a larger fractal dimension in pore size and variance yields a higher fraction of large pores; this leads to a better gas transport capacity; this is owing to a higher free gas transport ratio. A PSD with a smaller fractal dimension yields a lower cumulative gas production; this is because a smaller fractal dimension results in the reduction of gas transport efficiency. With an increase in the fractal dimension in pore size and variance, an apparent permeability-shifting effect is less obvious, and the sensitivity of this effect to a nanoscale PSD is also impaired. Higher fractal dimensions and variances result in higher cumulative gas production and a lower sensitivity of gas production to a nanoscale PSD, which is due to a better gas transport efficiency. The shale apparent permeability-shifting effect to nanoscale is more sensitive to a nanoscale PSD under a higher initial reservoir pressure, which makes gas production more sensitive to a nanoscale PSD. The findings of this study can help to better understand the influence of a nanoscale PSD on gas flow capacity and gas production.

Application of Heat Treatment to Prevent Fracturing Fluid-Induced Formation Damage and Enhance Matrix Permeability in Shale Gas Reservoirs

2021 ◽  
Author(s):  
Mingjun Chen ◽  
Peisong Li ◽  
Yili Kang ◽  
Xinping Gao ◽  
Dongsheng Yang ◽  
...  
Keyword(s):  
Heat Treatment ◽  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Gas Transport ◽  
Formation Damage ◽  
Transport Capacity ◽  
Fracturing Fluid ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
The Matrix

Abstract The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.

scholarly journals Numerical Simulation of Shale Gas Multiscale Seepage Mechanism-Coupled Stress Sensitivity

2019 ◽  
Vol 2019 ◽  
pp. 1-13 ◽  
Author(s):  
Xun Yan ◽  
Jing Sun ◽  
Dehua Liu
Keyword(s):  
Shale Gas ◽  
Gas Flow ◽  
Gas Transport ◽  
Sensitivity Coefficient ◽  
Stress Sensitivity ◽  
Gas Production ◽  
Molecular Flow ◽  
Adsorption Phenomenon ◽  
Gas Seepage ◽  
The Impact

The complexity of the gas transport mechanism in microfractures and nanopores is caused by the feature of multiscale and multiphysics. Figuring out the flow mechanism is of great significance for the efficient development of shale gas. In this paper, an apparent permeability model which covers continue, slip, transition, and molecular flow and geomechanical effect was presented. Additionally, a mathematical model comprising multiscale, geomechanics, and adsorption phenomenon was proposed to characterize gas flow in the shale reservoir. The aim of this paper is to investigate some important impacts in the process of gas transportation, which includes the shale stress sensitivity, adsorption phenomenon, and reservoir porosity. The results reveal that the performance of the multistage fractured horizontal well is strongly influenced by stress sensitivity coefficient. The cumulative gas production will decrease sharply when the shale gas reservoir stress sensitivity coefficient increases. In addition, the adsorption phenomenon has an influence on shale gas seepage and sorption capacity; however, the effect of adsorption is very weak in the early gas transport period, and the impact of later will increase. Moreover, shale porosity also greatly affects the shale gas transportation.

A FRACTAL PERMEABILITY MODEL FOR REAL GAS IN SHALE RESERVOIRS COUPLED WITH KNUDSEN DIFFUSION AND SURFACE DIFFUSION EFFECTS

Fractals ◽  
2020 ◽  
Vol 28 (01) ◽  
pp. 2050017 ◽  
Author(s):  
TAO WU ◽  
SHIFANG WANG
Keyword(s):  
Fractal Dimension ◽  
Surface Diffusion ◽  
Shale Gas ◽  
Gas Transport ◽  
Fractal Theory ◽  
Knudsen Diffusion ◽  
Apparent Permeability ◽  
Permeability Model ◽  
Real Gas ◽  
Shale Reservoirs

A better comprehension of the behavior of shale gas transport in shale gas reservoirs will aid in predicting shale gas production rates. In this paper, an analytical apparent permeability expression for real gas is derived on the basis of the fractal theory and Fick’s law, with adequate consideration of the effects of Knudsen diffusion, surface diffusion and flexible pore shape. The gas apparent permeability model is found to be a function of microstructural parameters of shale reservoirs, gas property, Langmuir pressure, shale reservoir temperature and pressure. The results show that the apparent permeability increases with the increase of pore area fractal dimension and the maximum effective pore radius and decreases with an increase of the tortuosity fractal dimension; the effects of Knudsen diffusion and surface diffusion on the total apparent permeability cannot be ignored under high-temperature and low-pressure circumstances. These findings can contribute to a better understanding of the mechanism of gas transport in shale reservoirs.

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