scholarly journals Evolution of Production and Transport Characteristics of Steeply-Dipping Ultra-Thick Coalbed Methane Reservoirs

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5081 ◽  
Author(s):  
Shun Liang ◽  
Hao Han ◽  
Derek Elsworth ◽  
Xuehai Fu ◽  
Qiangling Yao ◽  
...  
Keyword(s):  
Production Rate ◽  
Coalbed Methane ◽  
Water Saturation ◽  
Initial Pressure ◽  
Gas Production ◽  
Low Rank ◽  
Absolute Permeability ◽  
Fluid Saturation ◽  
Cbm Production ◽  
Strong Control

The large spatial variability of in-situ stress and initial reservoir pressure in steeply-dipping ultra-thick coalbed methane (UTCBM) reservoirs exert strong control on the initial distribution of stress-sensitive permeability. This results in significant differences in the propagation of reservoir depressurization, gas production characteristics, distribution of fluid saturation, and evolution of permeability relative to flat-lying and thin counterpart coalbed methane (CBM) reservoirs. We contrast these responses using the Fukang mining area of the Junggar Basin, Xinjiang, China, as a type-example using coupled hydro-mechanical modeling. Production response indicates: (1) Dual peaks in CBM production rate, due to the asynchronous changes in the gas production rate in each the upper and lower sections of the reservoir; (2) higher depressurization and water saturation levels in the lower section of the reservoir relative to the upper at any given distance from the production well that ameliorate with time to be similar to those of standard horizontal reservoirs; (3) the heterogeneity in effective stress is further amplified by the asymmetry of the initial pressure drawdown distribution of the reservoir to exert extreme control on the down-dip evolution of absolute permeability—with implications for production. Field drainage data and simulation results obtained in this study more accurately reflect the drainage characteristics of the steeply-dipping UTCBM reservoirs. For ultra-thick low-rank coal seams, permeability anisotropy plays an important role in determining the utility of horizontal wells and hydraulic fracturing to maximize rates and yields CBM production, and requiring further study.

scholarly journals Laboratory Measurements of the Relative Permeability of Coal: A Review

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5568
Author(s):  
Shaicheng Shen ◽  
Zhiming Fang ◽  
Xiaochun Li
Keyword(s):  
Carbon Dioxide ◽  
Relative Permeability ◽  
Coalbed Methane ◽  
Water Saturation ◽  
Gas Production ◽  
Absolute Permeability ◽  
Permeability Measurement ◽  
Mixed Gas ◽  
Practical Engineering ◽  
Relative Permeability Curves

The relative permeability of coal to gas and water is an essential parameter for characterizing coalbed methane (CBM) reservoirs and predicting coal seam gas production, particularly in numerical simulations. Although a variety of studies related to the relative permeability of coals have been conducted, the results hardly meet the needs of practical engineering applications. To track the dynamic development of relative permeability measurements in the laboratory, discover the deficiencies, and discuss further work in this field, this paper investigates the relative permeability measurement preparation work and laboratory methods and summarizes the development of techniques used to determine the water saturation during experimentation. The previously determined relative permeability curves are also assembled and classified according to coal rank and the absolute permeability. It is found that the general operations in the relative permeability measurement process are still not standardized. The techniques applied to determine the water saturation of coal in experiments have been refined to some extent, but no optimal technique has been recognized yet. New techniques, such as the incorporation of high-precision differential pressure gauges, can be used to determine the water production during relative permeability measurement. In addition, the existing relative permeability data are limited, and no study has focused on supercritical carbon dioxide-water and mixed gas (methane and carbon dioxide)-water relative permeability measurements. To meet the requirements of actual projects, further research on this topic must be conducted.

Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 397-407 ◽  
Author(s):  
Mashhad Mousa Fahes ◽  
Abbas Firoozabadi
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
High Temperatures ◽  
Gas Production ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Absolute Permeability ◽  
Low Permeability ◽  
Gas Well ◽  
Water Blocking

Summary Wettability of two types of sandstone cores, Berea (permeability on the order of 600 md), and a reservoir rock (permeability on the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90C. In this work, chemicals previously used at 90C for wettability alteration are found to be ineffective at 140C. New chemicals are used which alter wettability at high temperatures. The results show that:wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures,wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions,wettability alteration results in improved gas productivity, andwettability alteration does not have a measurable effect on the absolute permeability of the rock for some chemicals. We also find the reservoir rock, unlike Berea, is not strongly water-wet in the gas/water/rock system. Introduction A sharp reduction in gas well deliverability is often observed in many low-permeability gas-condensate reservoirs even at very high reservoir pressure. The decrease in well deliverability is attributed to condensate accumulation (Hinchman and Barree 1985; Afidick et al. 1994) and water blocking (Engineer 1985; Cimolai et al. 1983). As the pressure drops below the dewpoint, liquid accumulates around the wellbore in high saturations, reducing gas relative permeability (Barnum et al. 1995; El-Banbi et al. 2000); the result is a decrease in the gas production rate. Several techniques have been used to increase gas well deliverability after the initial decline. Hydraulic fracturing is used to increase absolute permeability (Haimson and Fairhurst 1969). Solvent injection is implemented in order to remove the accumulated liquid (Al-Anazi et al. 2005). Gas deliverability often increases after the reduction of the condensate saturation around the wellbore. In a successful methanol treatment in Hatter's Pond field in Alabama (Al-Anazi et al. 2005), after the initial decline in well deliverability by a factor of three to five owing to condensate blocking, gas deliverability increased by a factor of two after the removal of water and condensate liquids from the near-wellbore region. The increased rates were, however, sustained for a period of 4 months only. The approach is not a permanent solution to the problem, because the condensate bank will form again. On the other hand, when hydraulic fracturing is used by injecting aqueous fluids, the cleanup of water accumulation from the formation after fracturing is essential to obtain an increased productivity. Water is removed in two phases: immiscible displacement by gas, followed by vaporization by the expanding gas flow (Mahadevan and Sharma 2003). Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2003; Penny et al. 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al. 1989; Sognesand 1991; Baig et al. 2005).

scholarly journals Effects of Irreducible Fluid Saturation and Gas Entry Pressure on Gas Production from Hydrate-Bearing Clayey Silt Sediments by Depressurization

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-20
Author(s):  
Xiaolong Ma ◽  
Youhong Sun ◽  
Wei Guo ◽  
Rui Jia ◽  
Bing Li
Keyword(s):  
Water Saturation ◽  
Gas Production ◽  
Production Volume ◽  
Water Production ◽  
Shenhu Area ◽  
Gas Saturation ◽  
Fluid Saturation ◽  
Entry Pressure ◽  
Clayey Silt ◽  
Irreducible Water Saturation

Gas hydrates in the Shenhu area are mainly hosted in clayey silt sediments, which have the relatively high irreducible fluid saturation and gas entry pressure. And then, they will have an impact on gas production from hydrate-bearing clayey silt sediments, which was evaluated by the numerical simulations of SH2 site in Shenhu area in this paper. The results showed that, with the increase in irreducible water saturation and irreducible gas saturation, the amount of water production and gas production was obviously reduced. When the irreducible water saturation increased from 0.10 to 0.50, the cumulative CH4 production volume decreased from 1668799 m3 to 1536262 m3, and the cumulative water production volume dropped from 620304 m3 to 564797 m3, respectively. When the irreducible gas saturation increased from 0.01 to 0.05, the cumulative CH4 production volume dropped from 1812522 m3 to 1622121 m3, and the cumulative water production volume dropped from 672088 m3 to 600617 m3, respectively. In addition, the capillary pressure increased obviously with the increase in gas entry pressure, but the effect on gas production was small and the effect on water production could be negligible. In conclusion, irreducible water and gas saturation had an important effect on the gas production from gas hydrate, whereas the effects of gas entry pressure could be ignored.

Influence of Engineering Measurements on the Desorption and Production of CBM Wells by Eclipse

2013 ◽  
Vol 868 ◽  
pp. 700-704 ◽  
Author(s):  
Rui Wang ◽  
Fan Dong ◽  
Qing Zhong Zhu ◽  
Yan Hui Yang ◽  
Tian Peng Yao
Keyword(s):  
Coalbed Methane ◽  
Production Capacity ◽  
Gas Production ◽  
Simulation Software ◽  
Stage Of Development ◽  
Cbm Production ◽  
Stable Yield ◽  
Yield Time ◽  
Coal Reservoir ◽  
The Impact

Desorption of Coalbed Methane is one of the key controls to CBM recovery ratio and production capacity. This paper discusses the impact of engineered measures on CBM overall desorption and production capacity with CBM model of Eclipse numerical simulation software. The simulation results show that: with the extension of hydraulic fracture half-length, overall desorption of coal reservoir increased and CBM production capacity improved, daily gas production, maximum gas production and stable yield time increased correspondingly; in different deployment of spacing and well network, the smaller spacing is beneficial to the overall desorption of coal reservoir, but its production can not keep stability because of the serious decline in the late stage of development, while the larger spacing shows in the opposite way.

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 Microbial Simulation Experiment on Enhancing Coalbed Methane Production

2019 ◽  
Author(s):  
Chen Hao ◽  
Qin Yong ◽  
Zhou Shangwen ◽  
Wang Hongyan ◽  
Chen Zhenhong ◽  
...  
Keyword(s):  
Methane Production ◽  
Coalbed Methane ◽  
Simulation Experiment ◽  
Bacterial Species ◽  
Gas Production ◽  
Gas Generation ◽  
Exogenous Bacteria ◽  
Different Temperatures ◽  
Cbm Production ◽  
Coalbed Methane Production

Coalbed Methane(CBM) production enhancement for single wells is a big problem to CBM industrialization. Low production is due to insufficient gas generation by thermogenic. Luckily, Biogenic gas was found in many areas and its supply is assumed to improve coalbed methane production. Therefore, microbial simulation experiment will demonstrate the effectiveness of the assumption. From microbial simulation experiment on different coal ranks, it is found that microbes can use coals to produce biogas under laboratory conditions. With different temperatures for different experiments, it turns out that the gas production at 35 ℃ is greater than that at 15℃,indicating that 35℃ is more suitable for microbes to produce gas. According to quantitative experiments, adding exogenous nutrients or exogenous bacteria can improve CBM production. Moreover, the production enhancement ratio can reach up to 115% under the condition of adding exogenous bacterial species, while the ratio for adding nutrients can be up to 144%.

scholarly journals Influence of Intrinsic Permeability on the Production Performance of Shenhu Hydrate Sediment through Depressurization

2019 ◽  
Vol 118 ◽  
pp. 01008
Author(s):  
Yingrui Ma ◽  
Shuxia Li ◽  
Didi Wu
Keyword(s):  
Production Rate ◽  
Gas Production ◽  
Production Performance ◽  
Absolute Permeability ◽  
Reservoir Pressure ◽  
Intrinsic Permeability ◽  
Reservoir Temperature ◽  
Natural Gas Hydrate ◽  
Hydrate Dissociation ◽  
Hydrate Reservoirs

Natural gas hydrate(NGH) is a clean resource with huge reserves. The depressurization method is an economical and effective exploitation method. In the process of depressurization, reservoir absolute permeability has an important influence on production results. Based on the data of Shenhu hydrate reservoirs, this paper established a depressurization production numerical simulation model. Then, the production performances such as pressure, temperature, gas production rate, cumulative gas production, and hydrate dissociation effect are all studied under different permeability conditions.study the change of reservoir pressure, gas production rate, cumulative gas production, reservoir temperature change and hydrate dissociation effect under different permeability conditions. Results show that higher permeability is conducive to the depressurization of hydrate reservoirs.

scholarly journals Numerical analysis of drainage rate for multilayer drainage coalbed methane well group in Southern Qinshui basin

2020 ◽  
Vol 38 (5) ◽  
pp. 1535-1558
Author(s):  
Qiujia Hu ◽  
Shiqi Liu ◽  
Shuxun Sang ◽  
Huihuang Fang ◽  
Ashutosh Tripathy ◽  
...  
Keyword(s):  
Pressure Drop ◽  
Coal Seam ◽  
Coalbed Methane ◽  
Gas Production ◽  
Hydraulic Pressure ◽  
Qinshui Basin ◽  
Well Production ◽  
Drainage Rate ◽  
Southern Qinshui Basin ◽  
Cbm Production

Multilayer drainage is one of the important technologies for coalbed methane (CBM) production in China. In this study, a multi-field fully coupled mathematical model for CBM production was established to analyze the multilayer drainage of CBM well group in southern Qinshui basin. Based on the numerical simulation results, the characteristics of CBM well production under different drainage rates and key factors influencing the CBM production were further discussed. The results show that the effect of an increased drainage rate on gas production of CBM wells and CBM recovery of No.3 coal seam is not significant. However, it significantly improved the gas production of CBM wells and CBM recovery of No.15 coal seam. After a long period of production, the CBM content in No.3 coal seam has reduced to a low level and the pressure drop potential of No.3 coal seam is insignificant, which are important reasons for the insignificant increase of CBM production even under a drainage rate of 2 to 7 times. Conversely, No.15 coal seam has larger residual CBM content and increasing the drainage rate can significantly improve the pressure drop and superimposed well interference of No.15 coal seam, which means No.15 coal seam has greater production potential than No.3 coal seam. Therefore, it is recommended to improve the gas production and CBM recovery in No.15 coal seam by increasing the drainage rate, and the average hydraulic pressure drop should be 0.018–0.031 MPa/day. The influence of effective stress is weak in No.3 and No.15 coal seam, and the coal seam permeability is largely influenced by the shrinkage of coal matrix caused by CBM desorption. This indicates the feasibility of increase in gas production from CBM wells by increasing the drainage rate.

scholarly journals Numerical Simulation Research on Well Pattern Optimization in High–Dip Angle Coal Seams: A Case of Baiyanghe Block

2021 ◽  
Vol 9 ◽  
Author(s):  
Hongli Wang ◽  
Xiao Zhang ◽  
Suian Zhang ◽  
Hongxing Huang ◽  
Jun Wang
Keyword(s):  
Coal Seam ◽  
Coalbed Methane ◽  
Horizontal Well ◽  
Gas Production ◽  
Low Rank ◽  
Water Migration ◽  
Coal Seams ◽  
Well Pattern ◽  
Dip Angle ◽  
Desorption Model

The Baiyanghe block in Fukang, Xinjiang, China, is rich in coalbed methane (CBM) resources, and several pilot experimental wells have yielded high production. Due to the high dip angle (35–55°) of the coal seam in this area, the lack of understanding of the geological characteristics, the physical properties of coal, and gas–water migration law lead to immature development techniques and poor overall development benefits. We first conducted desorption and adsorption tests on low-rank coal of this area and found residual gas in the coal. We established a coalbed methane desorption model suitable for this area by modifying the isotherm adsorption model. Next, by analyzing the influence of the gas–water gravity differentiation in the high–dip angle coal seam and the shallow fired coalbed methane characteristics in this area, we discovered the leakage of CBM from the shallow exposed area of the coal seam. Given the particular physical property of coal and gas–water migration characteristics in this area, we optimized the well pattern: (i) the U-shaped along-dip horizontal well group in coal seams is the main production well for gas production with a spacing distance of 312 m; (ii) a multistage fracturing well drilled in the floor of coal is for water production; and (iii) vertical wells with a spacing distance of 156 m in the shallow area is to capture CBM leakage. Using numerical simulation and net present value (NPV) economics models, we optimized the well pattern details. Applying our CBM desorption model, the numerical simulator can improve the accuracy of the low-rank coalbed methane productivity forecast. The optimization results demonstrated the following: 1) the cumulative gas production of single U-shaped well increased by 89% with the optimal well spacing, 2) the cumulative gas production of the well group increased by 87.54% after adding the floor staged horizontal well, and 3) the amount of CBM leakage decrease by 67.59%.

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.

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