Productivity Prediction of Coalbed Methane Considering the Permeability Changes in Coal

2014 ◽  
Author(s):  
H.. Chen ◽  
M.. Li ◽  
Y.. Zhang ◽  
C.. Liu ◽  
Y.. Li
Keyword(s):  
Numerical Model ◽  
Coalbed Methane ◽  
Field Data ◽  
Gas Production ◽  
Phase Flow ◽  
Two Phase ◽  
Gas Desorption ◽  
Permeability Changes ◽  
Cbm Production ◽  
Production Period

Abstract This paper describes a three-dimensional numerical model for predicting the coalbed methane (CBM) production. The model describes single phase gas desorption from coal matrix, diffusion to the fracture and two-phase flow of gas and water in the natural fracture system as well as the permeability changes in coal which result from effective stress changes and matrix shrinkage due to gas desorption. The model was discretized by a finite difference method. The implicit pressure-explicit saturation (IMPES) method was used to solve the two-phase flow equations and gas desorption equation was solved implicitly. The numerical model was validated by the field data from Qinshui basin in China. Based on the model, the impact of various reservoir and Langmuir isothermal adsorption parameters on the gas production was investigated. The results show that the gas production rate of the coalbed methane predicted by this model is in good accordance with the field data. The permeability near the wellbore dramatically decreases as the reservoir pressure drops at the early production period while at the later production period, the permeability near the wellbore increases because of the matrix shrinkage. The permeability changes far away from the wellbore are not so remarkable. In addition, the gas production rate increases with the increased permeability, seam thickness and Langmuir pressure constant while it decreases with the increased porosity and Langmuir volume constant. The numerical model can be used to predict and analyze the production performance of CBM reservoirs and the research results provide theoretical support for CBM production.

Effect of Pressure-Propagation Behavior on Production Performance: Implication for Advancing Low-Permeability Coalbed-Methane Recovery

SPE Journal ◽  
2018 ◽  
Vol 24 (02) ◽  
pp. 681-697 ◽  
Author(s):  
Zheng Sun ◽  
Juntai Shi ◽  
Keliu Wu ◽  
Tao Zhang ◽  
Dong Feng ◽  
...  
Keyword(s):  
Prediction Model ◽  
Coalbed Methane ◽  
Control Method ◽  
Gas Production ◽  
Production Performance ◽  
Phase Flow ◽  
Two Phase ◽  
Propagation Behavior ◽  
Flow Stage ◽  
Pressure Propagation

Summary Low-permeability coalbed-methane (CBM) reservoirs possess unique pressure-propagation behavior, which can be classified further as the expansion characteristics of the drainage area and the desorption area [i.e., a formation in which the pressure is lower than the initial formation pressure and critical-desorption pressure (CDP), respectively]. Inevitably, several fluid-flow mechanisms will coexist in realistic coal seams at a certain production time, which is closely related to dynamic pressure and saturation distribution. To the best of our knowledge, a production-prediction model for CBM wells considering pressure-propagation behavior is still lacking. The objective of this work is to perform extensive investigations into the effect of pressure-propagation behavior on the gas-production performance of CBM wells. First, the pressure-squared approach is used to describe the pressure profile in the desorption area, which has been clarified as an effective-approximation method. Also, the pressure/saturation relationship that was developed in our previous research is used; therefore, saturation distribution can be obtained. Second, an efficient iteration algorithm is established to predict gas-production performance by combining a new gas-phase-productivity equation and a material-balance equation. Finally, using the proposed prediction model, we shed light on the optimization method for production strategy regarding the entire production life of CBM wells. Results show that the decrease rate of bottomhole pressure (BHP) should be slow at the water single-phase-flow stage, fast at the early gas/water two-phase-flow stage, and slow at the late gas/water two-phase-flow stage, which is referred to as the slow/fast/slow (SFS) control method. Remarkably, in the SFS control method, the decrease rate of the BHP at each period can be quantified on the basis of the proposed prediction model. To examine the applicability of the proposed SFS method, it is applied to an actual CBM well in Hancheng Field, China, and it enhances the cumulative gas production by a factor of approximately 1.65.

scholarly journals A Discrete Fracture Modeling Approach for Analysis of Coalbed Methane and Water Flow in a Fractured Coal Reservoir

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-15
Author(s):  
Tianran Ma ◽  
Hao Xu ◽  
Chaobin Guo ◽  
Xuehai Fu ◽  
Weiqun Liu ◽  
...  
Keyword(s):  
Water Flow ◽  
Coalbed Methane ◽  
Fluid Transport ◽  
Fracture Model ◽  
Phase Flow ◽  
Two Phase ◽  
Discrete Fracture Model ◽  
Discrete Fracture ◽  
Fractured Coal ◽  
Cbm Production

As a complex two-phase flow in naturally fractured coal formations, the prediction and analysis of CBM production remain challenging. This study presents a discrete fracture approach to modeling coalbed methane (CBM) and water flow in fractured coal reservoirs, particularly the influence of fracture orientation, fracture density, gravity, and fracture skeleton on fluid transport. The discrete fracture model is first verified by two water-flooding cases with multi- and single-fracture configurations. The verified model is then used to simulate CBM production from a discrete fractured reservoir using four different fracture patterns. The results indicate that fluid behavior is significantly affected by orientation, density, and fracture connectivity. Finally, several cases are performed to investigate the influence of gravity and fracture skeleton. The simulation results show that gas migrates upwards to the top reservoir during fluid extraction owing to buoyancy and the connected fracture skeleton plays a dominant role in fluid transport and methane production efficiency. Overall, the developed discrete fracture model provides a powerful tool to study two-phase flow in fractured coal reservoirs.

Impact of Various Parameters on the Production of Coalbed Methane

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 910-923 ◽  
Author(s):  
Zhongwei Chen ◽  
Jishan Liu ◽  
Akim Kabir ◽  
Jianguo Wang ◽  
Zhejun Pan
Keyword(s):  
Time Constant ◽  
Coalbed Methane ◽  
Dominant Role ◽  
Gas Production ◽  
Fracture Permeability ◽  
Permeability Model ◽  
Gas Desorption ◽  
Desorption Time ◽  
Matrix Blocks ◽  
Cbm Production

Summary Coalbed-methane (CBM) reservoirs are naturally fractured formations, comprising both permeable fractures and matrix blocks. The interaction between fractures and matrix presents a great challenge for the forecast of CBM reservoir performance. In this work, a dual-permeability model was applied to study the parameter sensitivity on the CBM production, because the dual-permeability model incorporates not only the influence from matrix and fractures but also that between adjacent matrix blocks. The mass exchange between two systems is defined as a function of desorption time constant at the standard condition, coal matrix porosity, and the difference of gas pressure between two systems. Correspondingly, gas diffusivity in matrix is considered as a variable and represented by a function of shape factor, gas desorption time, and reservoir pressure. These relations are integrated into a fully coupled numerical model of coal geomechanical deformation and gas desorption/gas flow in both systems. This numerical approach demonstrates the important nonlinear effects of the complex interaction between matrix and fractures on CBM production behaviors that cannot be recovered without rigorously incorporating geomechanical influences. This model was then used to investigate the sensitivity of CBM extraction behavior to different controlling factors, including gas desorption time constant, initial fracture permeability, fracture spacing, swelling capacity, desorption capacity, production pressure, and fracture and matrix porosities. Modeling results show that the peak magnitudes of gas-production rate increase with initial fracture permeability, sorption and swelling capacities, and matrix porosity, and decrease with gas desorption time constant and production pressure. These results also show dramatic increase in gas-production efficiency with decreasing magnitudes of fracture spacing. The comparison of the transient contributions of the desorbed gas and the free phase gas from the matrix system to gas production shows that the free phase gas plays the dominant role at the early stage, but diminishes when the adsorption phase gas takes over the dominant role, indicating the necessity of incorporating free phase gas impact in simulation models. The numerical model was also applied to match the history data from a gas-production well. A better matching result than that for the single-permeability model demonstrates the potential capability of the dual-permeability model for the forecast of CBM production.

scholarly journals A Comprehensive Coal Reservoir Classification Method Base on Permeability Dynamic Change and Its Application

Energies ◽  
2020 ◽  
Vol 13 (3) ◽  
pp. 644 ◽  
Author(s):  
Xinlu Yan ◽  
Songhang Zhang ◽  
Shuheng Tang ◽  
Zhongcheng Li ◽  
Yongxiang Yi ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
Dynamic Change ◽  
Initial Permeability ◽  
Gas Production ◽  
Gas Desorption ◽  
Reservoir Permeability ◽  
Geological Conditions ◽  
Production Stages ◽  
Productivity Potential ◽  
Coal Reservoir

Due to the unique adsorption and desorption characteristics of coal, coal reservoir permeability changes dynamically during coalbed methane (CBM) development. Coal reservoirs can be classified using a permeability dynamic characterization in different production stages. In the single-phase water flow stage, four demarcating pressures are defined based on the damage from the effective stress on reservoir permeability. Coal reservoirs are classified into vulnerable, alleviative, and invulnerable reservoirs. In the gas desorption stage, two demarcating pressures are used to quantitatively characterize the recovery properties of permeability based on the recovery effect of the matrix shrinkage on permeability, namely the rebound pressure (the pressure corresponding to the lowest permeability) and recovery pressure (the pressure when permeability returns to initial permeability). Coal reservoirs are further classified into recoverable and unrecoverable reservoirs. The physical properties and influencing factors of these demarcating pressures are analyzed. Twenty-six wells from the Shizhuangnan Block in the southern Qinshui Basin of China were examined as a case study, showing that there is a significant correspondence between coal reservoir types and CBM well gas production. This study is helpful for identifying geological conditions of coal reservoirs as well as the productivity potential of CBM wells.

scholarly journals A numerical model for simulating two-phase flow through porous media

1989 ◽  
Vol 13 (5) ◽  
pp. 268-281 ◽  
Author(s):  
Anant R. Kukreti ◽  
Yatendra Rajapaksa
Keyword(s):  
Porous Media ◽  
Numerical Model ◽  
Two Phase Flow ◽  
Phase Flow ◽  
Flow Through Porous Media ◽  
Two Phase ◽  
Flow Through

Multiphase Transient Slugging Flow in Subsea Oil and Gas Production

2016 ◽  
Author(s):  
Zhenhua Zhang ◽  
Longbin Tao
Keyword(s):  
Data Analysis ◽  
Temperature Distribution ◽  
Numerical Model ◽  
Slug Flow ◽  
Field Data ◽  
Oil And Gas ◽  
Gas Production ◽  
Worst Case ◽  
Oil And Gas Production ◽  
Significant Difference

Slug flow in horizontal pipelines and riser systems in deep sea has been proved as one of the challenging flow assurance issues. Large and fluctuating gas/liquid rates can severely reduce production and, in the worst case, shut down, depressurization or damage topside equipment, such as separator, vessels and compressors. Previous studies are primarily based on experimental investigations of fluid properties with air/water as working media in considerably scaled down model pipes, and the results cannot be simply extrapolated to full scale due to the significant difference in Reynolds number and other fluid conditions. In this paper, the focus is on utilizing practical shape of pipe, working conditions and fluid data for simulation and data analysis. The study aims to investigate the transient multiphase slug flow in subsea oil and gas production based on the field data, using numerical model developed by simulator OLGA and data analysis. As the first step, cases with field data have been modelled using OLGA and validated by comparing with the results obtained using PIPESYS in steady state analysis. Then, a numerical model to predict slugging flow characteristics under transient state in pipeline and riser system was set up using multiphase flow simulator OLGA. One of the highlights of the present study is the new transient model developed by OLGA with an added capacity of newly developed thermal model programmed with MATLAB in order to represent the large variable temperature distribution of the riser in deep water condition. The slug characteristics in pipelines and temperature distribution of riser are analyzed under the different temperature gradients along the water depth. Finally, the depressurization during a shut-down and then restart procedure considering hydrate formation checking is simulated. Furthermore, slug length, pressure drop and liquid hold up in the riser are predicted under the realistic field development scenarios.

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

Numerical and Mechanistic Modelling of Two-Phase Liquid-Gas Flow’s Pressure Drop Across Sharp-Edged Orifices

2019 ◽  
Author(s):  
Zurwa Khan ◽  
Reza Tafreshi ◽  
Matthew Franchek ◽  
Karolos Grigoriadis
Keyword(s):  
Numerical Model ◽  
Pressure Drop ◽  
Relative Error ◽  
Two Phase Flow ◽  
Mechanistic Model ◽  
Gas Mixture ◽  
Phase Flow ◽  
Two Phase ◽  
Pressure Drops ◽  
Phase Liquid

Abstract Pressure drop estimation across orifices for two-phase liquid-gas flow is essential to size valves and pipelines and decrease the probability of unsafe consequences or high costs in petroleum, chemical, and nuclear industries. While numerically modeling flow across orifices is a complex task, it can assess the effect of numerous orifice designs and operation parameters. In this paper, two-phase flow across orifices has been numerically modeled to investigate the effect of different fluid combinations and orifice geometries on pressure drop. The orifice is assumed to be located in a pipe with fully-developed upstream and downstream flow. Two liquid-gas fluid combinations, namely water-air, and gasoil liquid-gas mixture were investigated for different orifice to pipe area ratios ranging from 0.01 to 1 for the superficial velocity of 10 m/s. Volume of Fluid multiphase flow model along with k-epsilon turbulence model were used to estimate the pressure distribution of liquid-gas mixture along the pipe. The numerical model was validated for water-air with mean relative error less than 10.5%. As expected, a decrease in orifice to pipe area ratio resulted in larger pressure drops due to an increase in the contraction coefficients of the orifice assembly. It was also found that water-air had larger pressure drops relative to gasoil mixture due to larger vortex formation downstream of orifices. In parallel, a mechanistic model to directly estimate the local two-phase pressure drop across orifices was developed. The gas void fraction was predicted using a correlation by Woldesemayat and Ghajar, and applied to separated two-phase flow undergoing contraction and expansion due to an orifice. The model results were validated for different orifices and velocities, with the overall relative error of less than 40%, which is acceptable due to the uncertainties associated with measuring experimental pressure drop. Comparison of the developed numerical and mechanistic model showed that the numerical model is able to achieve a higher accuracy, while the mechanistic model requires minimal computation.

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