scholarly journals A new fracture permeability model of CBM reservoir with high-dip angle in the southern Junggar Basin, NW China

2018 ◽  
Vol 37 (1) ◽  
pp. 125-143 ◽  
Author(s):  
Shiyu Yang ◽  
Yidong Cai ◽  
Ren Wei ◽  
Yingfang Zhou
Keyword(s):  
Coalbed Methane ◽  
Junggar Basin ◽  
Well Testing ◽  
Well Test ◽  
Fracture Permeability ◽  
Permeability Model ◽  
Fracture Porosity ◽  
Nw China ◽  
Coalbed Methane Reservoir ◽  
Dip Angle

Predicting the permeability of coalbed methane (CBM) reservoirs is significant for coalbed methane exploration and coalbed methane development. In this work, a new fracture permeability model of coalbed methane reservoir with high-dip angle in the southern Junggar Basin, NW China is established based on the Poiseuille and Darcy laws. The fracture porosity in coalbed methane reservoir is calculated by applying 3D finite element method. The formation cementing index m was calculated by combining fractal theory and the data of acoustic logging, compensated neutron logging, and density logging with the space method. Based on Poiseuille and Darcy laws, the curvature τ is introduced to derive this new method for obtaining the permeability of the original fractures in coalbed methane reservoirs. Moreover, this newly established permeability model is compared with the permeability from the well testing, which shows a very good correlation between them. This model comprehensively includes the effects of fracture porosity, reservoir pore structure, and development conditions on fracture permeability. Finally, the permeability prediction of coalbed methane reservoir with high-dip angle in the southern Junggar Basin, NW China is conducted, which correlates very well with the well test permeability ( R2 = 0.83). Therefore, this model can be used to accurately predict the coalbed methane reservoir permeability of low rank coals in the southern Junggar Basin. The permeability of the No.43 coalbed methane reservoir for the coalbed methane wells without well testing data is evaluated, which ranges from 0.000251 to 0.379632 mD. This significant change in permeability may indicate a complex coalbed methane reservoir structure in the southern Junggar Basin, NW China.

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.

A Permeability Model for Undersaturated Coalbed Methane Reservoirs Considering the Coal Matrix Shrinkage Effect

2013 ◽  
Vol 807-809 ◽  
pp. 2413-2420 ◽  
Author(s):  
Jun Long Zhao ◽  
Da Zhen Tang ◽  
Hao Xu ◽  
Yan Jun Meng ◽  
Yu Min Lv
Keyword(s):  
Pore Pressure ◽  
Coalbed Methane ◽  
Well Test ◽  
Dynamic Prediction ◽  
Permeability Model ◽  
Matrix Shrinkage ◽  
New Model ◽  
Shrinkage Effect ◽  
The Matrix

With the analysis of key elements on the strain state of coal, a permeability dynamic prediction model which is divided by the critical desorption pressure for undersaturated coalbed methane (CBM) reservoirs was established on the basis of pore pressure and considering the matrix shrinkage effect of coal. The law between permeability and pore pressure was analyzed during production with the new model. Through case study, the rationality of the model was also verified. The research shows that the degree of permeability changes mainly depends on the relationship between the critical desorption pressure and the rebound pressure which depends on the strength of the matrix shrinkage. Under the condition of equivalent matrix shrinkage, the reservoirs permeability rebounds better with high Young's modulus and low Poisson's ratio. Adjustment factor contributes to improve the influence of matrix shrinkage on permeability and the larger the matrix shrinkage strength is, the higher the permeability rebounds. PM model and CB model are similar to the new model. PM model limits the matrix shrinkage strength, and CB model is a special case of the new model. Comparing with the well test permeability, the new model is more reasonable to characterize the matrix shrinkage effect in the development process.

scholarly journals Coalbed methane reservoir evaluation in the Manas mining area, southern Junggar Basin

2017 ◽  
Vol 36 (1) ◽  
pp. 114-131 ◽  
Author(s):  
Yuan Yuan ◽  
Yue Tang ◽  
Yansheng Shan ◽  
Jiaqiang Zhang ◽  
Daiyong Cao ◽  
...  
Keyword(s):  
Coalbed Methane ◽  
Junggar Basin ◽  
Mining Area ◽  
Reservoir Evaluation ◽  
Coalbed Methane Reservoir

Hydrogeochemistry signatures of produced waters associated with coalbed methane production in the Southern Junggar Basin, NW China

2019 ◽  
Vol 26 (31) ◽  
pp. 31956-31980 ◽  
Author(s):  
Zheng Zhang ◽  
Detian Yan ◽  
Xinguo Zhuang ◽  
Shuguang Yang ◽  
Gang Wang ◽  
...  
Keyword(s):  
Methane Production ◽  
Coalbed Methane ◽  
Junggar Basin ◽  
Nw China ◽  
Produced Waters ◽  
Coalbed Methane Production

Analogy Analysis of Coalbed Methane Reservoir-Forming Conditions in Jixi Basin

2015 ◽  
Vol 733 ◽  
pp. 96-99 ◽  
Author(s):  
Yu Shuang Hu ◽  
Yu Gang Hao ◽  
Hui Ting Hu
Keyword(s):  
Coalbed Methane ◽  
The United States ◽  
Gas Content ◽  
Burial Depth ◽  
Oil Drilling ◽  
Black Warrior Basin ◽  
Reservoir Conditions ◽  
Coalbed Methane Reservoir ◽  
Dip Angle ◽  
Coal Reservoir

Based on coalbed methane geology theory, make use of coal and oil drilling data, from both of the coal reservoir characteristics and conservation conditions, Through comparative analysis of a number of geological factors of coalbed thickness, burial depth, metamorphic grade, gas content, roof and floor lithology, dip angle, etc, and found that there are many similarities between Jixi Basin and Black Warrior Basin in the United States of coalbed methane reservoir conditions. Compared to Black Warrior Basin, the advantages of Jixi Basin are that the coal metamorphism degree is high, the tired and single coalbed are thick, the closeness of roof and floor are good, the fault development and coalbed gas content are similar to it; the disadvantages of Jixi Basin are that the formation dip angle is large, the pressure gradient and permeability are small.

Water Imbibition of Coal and its Potential Influence on CBM Recovery

2020 ◽  
Author(s):  
Yanhai Chang
Keyword(s):  
Coalbed Methane ◽  
High Performance ◽  
Junggar Basin ◽  
Spontaneous Imbibition ◽  
Permeability Change ◽  
Permeability Model ◽  
Gas Recovery ◽  
Water Imbibition ◽  
Matrix Permeability ◽  
The Matrix

<p>Water /gas mobility and interaction in coal plays an important role in achieving the high performance of coalbed methane (CBM) recovery. A large volume of fracturing fluid is permeated into reservoir during the CBM development. The effect of the imbibed liquid on gas recovery is still controversial. To better understand this phenomenon, a systematical investigation of water dynamic imbibition and matrix permeability change during water imbibition were conducted experimentally using different coals collected from Qinshui, Ordos and Junggar Basin of China.</p><p>The research stimulates two different case of spontaneous imbibition and the special imbibition process and imbibition in different pores are concluded by analyzing the imbibition characteristics (i.e. imbibition ability, imbibition rate and imbibition dynamic). The water imbibes into smaller pores and larger pores simultaneously, in which the water imbibition rate is relevant to the porosity, permeability and wettability. The water imbibition in coal matrix can bring about the redistribution and existing state change of water, which probably one of the main factors causing the damage of the matrix permeability. By studying the permeability change and imbibition law, a permeability model is used to explain the influence of imbibition on permeability. Finally, the permeability is found as a function of sorting time and invasion depth, which will be useful for field applications.</p>

Use of Exclusion Zones in Mapping and Modeling Fracture Corridors

2010 ◽  
Vol 13 (04) ◽  
pp. 679-687 ◽  
Author(s):  
Sait I. Ozkaya
Keyword(s):  
Distance Matrix ◽  
Well Testing ◽  
Well Test ◽  
Exclusion Zone ◽  
Fracture Permeability ◽  
Reservoir Evaluation ◽  
Lost Circulation ◽  
Matrix Permeability ◽  
Water Breakthrough ◽  
Well Tests

Summary Fracture corridors are fault-related, subvertical, tabular fracture clusters that traverse the entire reservoir vertically and extend for several tens or hundreds of meters horizontally. Conductive fracture corridors may have significant permeability and may profoundly affect reservoir-flow dynamics. Therefore, it is important to map conductive fracture corridors deterministically for reservoir evaluation and well planning. Deterministic mapping of fracture corridors requires locating fracture corridors and assigning to them length, orientation, fluid conductivity, and connectivity. Estimation of orientation, length, and—especially—connectivity is a major challenge in fracture-corridor mapping. An exclusion zone is a region that cannot have a conductive fault or fracture corridor passing through. Borehole images, open-hole logs, flow profiles, and lost-circulation data can be used to identify horizontal wells with no fracture-corridor intersection. Well tests, production/injection history, Kh ratio (permeability times thickness) well-test/core ratio, first water arrival, and oil-column-thickness maps can be used to identify vertical “matrix” wells that do not intersect fracture corridors. Adjacent matrix wells may be surrounded by inferred exclusion zones. The confidence level of inferred exclusion zones depends on factors such as interwell distance, matrix permeability, width, orientation, and spacing of fracture corridors. Overlapping of exclusion zones from independent data sources such as well testing and oil-column thickness have higher confidence than non-overlapping zones. Only borehole images provide orientation and only well tests provide length of fracture corridors. In the absence of well testing and borehole imaging, exclusion zones provide constraints and aid both in locating fracture corridors and assigning them orientation and length. Perhaps the most significant contribution of exclusion zones to fracture-corridor mapping is in identifying interconnected and isolated fracture corridors. An interconnected network of fracture corridors may extend laterally for several kilometers as major fracture permeability pathways, which not only improve pressure support, bottom upsweep of oil, but also cause rapid water breakthrough.

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