Coalbed Methane Wells Research Articles

Bicarbonate alone does not totally explain the toxicity from major ions of coal bed derived waters to freshwater invertebrates

Concentrations of major ions in coal mine discharge waters and unconventional hydrocarbon produced waters derived from coal bed methane (CBM) production, are potentially harmful to freshwater ecosystems. Bicarbonate is a major constituent of produced waters from CBM and coal mining. However, little is known about the relative toxicity of differing ionic proportions, especially bicarbonate, found in these CBM waters. As all freshwater invertebrates tested are more acutely sensitive to sodium bicarbonate (NaHCO3) than sodium chloride (NaCl) or synthetic sea water, we tested the hypotheses that toxicity of CBM waters are driven by bicarbonate concentration, and waters containing a higher proportion of bicarbonate are more toxic to freshwater invertebrates than those with less bicarbonate. We compared the acute (96 h) lethal toxicity to six freshwater invertebrate species of NaHCO3 and two synthetic CBM waters, with ionic proportions representative of water from CBM wells across New South Wales (NSW) and Queensland (Qld), in Australia. The ranking of LC50 values expressed as total salinity was consistent with the hypotheses. However, when toxicity was expressed as bicarbonate concentration, the hypothesis that the toxicity of coal bed waters would be explained by bicarbonate concentration was not well supported, and other ionic components were either ameliorating or exacerbating the NaHCO3 toxicity. Our findings showed NaHCO3 was more toxic than NaCl and that the NaHCO3 proportion of synthetic CBM waters drives toxicity, however other ions are altering the toxicity of bicarbonate.

Determination of the degree of coal deformation and its effects on gas production in the southern Qinshui Basin, North China

Coal deformation significantly impacts coalbed methane (CBM) productivity. However, existing methods are incapable of quantitatively evaluating coal deformation on a high accuracy when there is limited core recovery from a CBM well. This study proposes a well logging coal structure index (WCSI) to quantify the degree of coal deformation. The WCSI of targets is calculated based on the data from well logs and coal cores, and it can also be estimated from well logs when no coal cores are recovered from wells. Thus, the WCSI can be applied to the regional-scale evaluation of coal deformation degree, and its effectiveness has been validated by data for 245 samples from the No. 3 coal seam in 55 exploration wells in the southern Qinshui Basin (SQB). Results indicate that the reservoir permeability and hydraulic fracturing effectiveness depend on the degree of coal seam deformation, which further affects the unique distribution of gas production in the known production regions in the SQB. Generally, the lowly deformed coal seam (WCSI (avg.) < 40) occurs mainly in the tectonically ‘stable’ regions (no faults or only small-scale faults development) where the micro-fractures/cleats in coal are not well developed. Low WCSI (avg.) commonly indicates low permeability (<0.06 mD) and poor hydraulic fracturing of the reservoir, resulting in relatively low gas production rate of wells in these regions. Secondly, the moderately deformed coal seam (40 < WCSI (avg.) < 60) is mainly found in areas close to moderate-scale faults, where coal seams have relatively high reservoir permeability (>0.06 mD) and hydraulic fracturing is easiest. This causes high gas production rate from wells in these regions. Thirdly, the highly deformed coal seam (WCSI (avg.) > 60) is generally found close to large-scale faults, indicating very low reservoir permeability (<0.03 mD) and the worst effectiveness from hydraulic fracturing of the reservoir, resulting in the lowest gas production rate of wells in these regions. In summary, the production efficiency from CBM wells in the SQB can thus be described in terms of the WCSI (avg.) value, and hence this parameter can help with preliminary forecasting gas production.

Pore Structure Characteristics and Adsorption and Desorption Capacity of Coal Rock after Exposure to Clean Fracturing Fluid.

In the hydraulic fracturing process, fracturing fluid contacts coal rock and physical and chemical reactions occur, which inevitably damage the pore structure of the coal rock and affect the adsorption and desorption capacity of the coal rock. In this paper, a low-temperature N2 adsorption method and scanning electron microscopy (SEM) were used to characterize coal samples. Using gas adsorption/desorption tests, high-, medium-, and low-rank coal samples before and after the clean fracturing fluid treatment were systematically studied. According to the relationship between coal pore structure parameters and gas adsorption/desorption characteristics, a correlation between the microscopic pore structure and the macroscopic gas adsorption/desorption characteristics of coal was obtained. The results show that the number of closed pores in high-, medium-, and low-rank coal samples increased after the clean fracturing fluid treatment. The micropore volume increased by 0.0009, 0.00143, and 0.0035 mL/g, respectively, and the specific surface area increased by 4.87, 9.06, and 57.60%. The fractal dimension also increased compared with that of raw coal. SEM analysis indicated that the influence degree of clean fracturing fluid treatment on the pore structure of different-rank coal samples was Gengcun low-rank coal > Pingba middle-rank coal > Jiulishan high-rank coal. The experimental results of methane adsorption and desorption showed that the adsorption capacity of the coal samples after clean fracturing fluid treatment was enhanced, which is related to increases in the micropore proportion, micropore volume, and specific surface area of the coal. The desorption capacity of the coal samples was also enhanced. The desorption rate of medium- and high-rank coal samples increased after the clean fracturing fluid treatment but that of low-rank coal samples decreased. The main reason is the increase in the number of micropores in low-rank coal, which enhances the gas adsorption ability and makes gas desorption difficult. Therefore, clean fracturing fluid is suitable for medium- and high-grade metamorphic coalbed methane mines. These research results provide a theoretical basis for the application of clean fracturing fluid in different coalbed methane wells.

Study on the Effect of Salinity and Water Content on CBM Adsorption/Desorption Characteristics of Coal Reservoir in Baode Block

The adsorption/desorption characteristics of a coal reservoir play an important role in coalbed methane (CBM) development. The proximate analysis, maceral analysis and methane isothermal adsorption/desorption experiment are carried out based on coal samples from no. 4+5 coal seam in Baode block. Combing with coal experimental data and the CBM well-produced water salinity data in the Baode block, the effect of salinity and water content on CBM adsorption/desorption characteristics of the coal reservoir and its influencing mechanism is discussed. The results show that the CBM adsorption and desorption capacity decreases with the increase of water salinity and the decrease value shows a decreasing trend. The increase of water salinity reduces the solubility of methane in coal seam water and then reduces the adsorption capacity of methane. With the increase of water content, the adsorption and desorption capacities of CBM decrease gradually. The CBM adsorption and desorption capacities decrease with the increase of water content in coal samples. The adsorption/desorption capacities of coal samples change rapidly in the low-water content stage and slowly in the high-water content stage. The competitive adsorption effect and water blocking effect between water and methane molecules are the main influencing mechanisms of water content on CBM adsorption/desorption. It can be seen that the salinity and water content will have a certain adverse impact on the adsorption and desorption capacity of CBM in the Baode block. The influence of the difference in water content and salinity in the coal seam cannot be ignored in reserve evaluation and productivity prediction of CBM. The continuous, stable, and effective drainage is one of the key factors to ensure the efficient development of CBM wells in the Baode block.

Coalbed Methane Industry Development Framework and Its Limiting Factors in China

The current average daily gas production of single coalbed methane (CBM) wells in China is less than 1,300 m3. The low production rate of CBM wells dramatically limits the sustainable development of the CBM industry in China. To promote CBM industry development, three universal geological factors, i.e., gas sources, channels, and driving force of the low production wells are analyzed, considering the various and complicated geological conditions of CBM reservoirs in China. Additionally, we find that the growth in proven CBM reserves should be greatly promoted as the CBM proven rate is only less than 3% by the end of 2020. The widespread CBM extraction mode based on depressurization via dewatering generates very limited effects in coal seams with notable deformation, high in situ stress, or little water. Therefore, a specific design of CBM development modes is proposed, according to the applicable geological conditions of different CBM development modes. It covers depressurization via dewatering, depressurization via stress release, and coal and CBM comining. Moreover, the regional governments play a key role in the development of the regional CBM industry, and favorable policies should be formulated to promote the multipoint development conditions across China. This study is concluded to provide a recommended development framework involving sustainable CBM production in China and its development processes.

Biogenic Methane Accumulation and Production in the Jurassic Low-Rank Coal, Southwestern Ordos Basin

Geological conditions are the key for coalbed methane (CBM) accumulation and production. However, the geological feature of CBM accumulation and production in the Jurassic of Ordos Basin lacks systematic and detailed evaluation, resulting in poor CBM production in this area. This study has determined the genetic types of gas according to geochemistry characteristics of the gas, the geological factors to control CBM accumulation and production performance were revealed, and a comprehensive method was established to evaluate favorable areas based on 32 sets of CBM well production data from Jurassic Yan’an Formation. The results show the coal macerals are rich in inertinite (41.13~91.12%), and the maximum reflectance of vitrinite (Ro,max) in coal is 0.56~0.65%. According to gas compositions and carbon isotopes analysis, the δ13C(CH4) is less than −55‰, and the content of heavy hydrocarbon is less than 0.05%. The value of C1/(C2 + C3) is 6800~98,000, that is, the CBM is a typical biogenic gas of low-rank coal. The CBM accumulation model is the secondary biogenic on the gentle slope of the basin margin, in which gas content is closely related to buried depth and hydrodynamic environment, i.e., the high gas content areas are mainly located in the groundwater weak runoff zone at the burial depth of 450 m~650 m, especially in the syncline. Meanwhile, gas production mainly depends on the location of the structure. The high gas production areas of vertical wells were distributed on the gentle slope with high gas content between anticline and syncline, and the horizontal wells with good performance were located near the core of the syncline. According to the above analysis combined with the random forest model, the study area was divided into different production favorable areas, which will provide a scientific basis for the CBM production wells.

In Situ Stress Distribution and Variation Monitored by Microseismic Tracking on a Fractured Horizontal Well: A Case Study from the Qinshui Basin.

In situ stress is an important parameter regulating the production of coalbed methane (CBM), and the monitoring of rock deformation can provide a description of the state of stress. Microseismic monitoring in a multistage fractured horizontal CBM well was conducted as a case study with a completion depth of 1445.36 m. The results show that there is a good correlation among the seismicity parameters, b-value, stress drop, fracture length, fracture density, and orientation. In the stress concentration region, the fracture is longer with a smaller density, where the b-value is lower. On the contrary, in the stress relaxation zone, the fracture is shorter with a complex shape, where the b-value is higher. Stress drop is relatively higher where fractures are concentrated, which indicate the areas with successful reservoir stimulation. The reliability of the above results was verified by the normal fault occurring between stages 7 and 8. In the area affected by the hanging wall of the normal fault (stage 6 and 7), the b-value is 0.38–0.39, while in the area affected by the footwall (stage 8 and 9), the b-value is 0.64–0.66. This phenomenon reflects an obvious stress concentration in the hanging wall of normal fault, which is consistent with the conventional understanding. The microseismic source parameters have great potential in evaluating reservoir stress. With further exploration of source parameters, microseismic will provide more support for CBM development.

An optimal selection method of wells for secondary fracturing in a single coal seam and its application

At present, methods including mathematical modeling, physical or numerical simulation, and in-situ monitoring have been generally adopted to determine evaluation parameters for coalbed methane (CBM) wells for secondary fracturing. These conventional methods either entail many assumptions, or some parameters are difficult to obtain, resulting in a certain deviation between the evaluation results and reality, or the application cost is high, preventing the monitoring of each CBM well. In view of this, an evaluation index system for the gas production potential, effective length of cracks formed by fracturing, and supporting length of proppant in cracks was established based on the system theory. The evaluation indices were characterized through production data, such as logging, fracturing and drainage, which could avoid potential bias in evaluation when only considering a certain parameter and ensured accuracy and practicability of the evaluation parameters for each well. Principal component analysis (PCA) and the entropy weight method (EWM) were used to obtain weights of evaluation parameters, which avoided the contradiction of contributions of various parameters to optimal selection and the rationalized results. In this way, a method for step-wise optimal selection of wells for secondary fracturing integrating construction of evaluation parameters, determination of critical values, and entropy evaluation was proposed. The results of an evaluation of the Shizhuang South Block of Qinshui Basin (Shanxi Province, China) indicate that wells whose three evaluation indices are satisfied are most preferable; wells that only meet the effective length of cracks formed by fracturing or effective supporting length of proppant in cracks can be selected; wells which do not meet the gas production potential or all of the three parameters cannot be selected.

Coalbed Methane Production Model Based on Random Forests Optimized by a Genetic Algorithm.

It is of great significance to evaluate and predict coalbed methane (CBM) production for the exploitation and exploration of CBM. The flow characteristics of gas and water are very complicated and important in the process of CBM exploitation. In recent years, machine learning has been introduced to analyze CBM well production and its influence based on the historical production data. However, there are some problems with the determination of hyperparameters in machine learning algorithms. Some previous random forests (RF) models of CBM production prediction were suitable for individual CBM wells, but for different types of CBM wells, a large amount of time is needed to adjust the hyperparameters. Therefore, a genetic algorithm (GA) was applied to optimize RF, and a hybrid GA–RF algorithm was presented to solve this problem, which can automatically adjust two important hyperparameters, ntree and mtry, and adapt different types of CBM wells. Meanwhile, the Pearson method and RF were carried out in this work to analyze the data of CBM well production to avoid multicollinearity caused by the improper selection of the model’s independent variables. The importance and correlation analysis of drainage control parameters, including casing pressure (Pc), bottom-hole pressure (Pb), stroke frequency (fs), liquid column depth (DL), daily decline of bottom-hole pressure (Pbd), and daily decline of casing pressure (Pcd) were obtained. It was found that the casing pressure, bottom-hole pressure, and stroke frequency had more effects on the gas production of CBM wells than other drainage control parameters. Furthermore, the correlation and importance order of the influencing factors were: Pc > Pb > fs > Pbd > Pcd > DL and Pc > Pb > fs > DL > Pbd > Pcd, respectively. A CBM production model based on the GA–RF algorithm was constructed to study and predict the gas production of CBM wells in Qinshui Basin, China. Compared with the production model based on RF, this model can automatically optimize its hyperparameters to adapt to different types of CBM wells, and the mean-square-error of the GA–RF algorithm can be reduced by 40–60% than that of RF. 93% of the training errors were less than 5%, and 89% of the prediction errors were less than 10%. The GA–RF model can spot promptly the main influencing factors of CBM production and has high accuracy for the production prediction of CBM wells.

Iterative Ensemble Kalman Smoother Applied to History-Matching Coalbed Methane Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTEC 208291, “Introducing Iterative Ensemble Kalman Smoother to History-Matching Horizontal Coalbed Methane Wells,” by Rubakumar Sankararaj, SPE, and Sylvain Ducroux, SPE, Resoptima, and Dan Kuznetsov, SPE, Arrow Energy, et al. The paper has not been peer reviewed. This study presents the iterative ensemble Kalman smoother applied to a low-permeability coalbed methane (CBM) field in Australia. All wells in the studied reservoir are completed with an artificial lift system and permanent downhole gauges. A forecast study was conducted to validate the history-matched ensemble. The results showed a good match of 12 months of the new production data not used in history matching, which highlights the robust prediction capabilities of the approach. Geology of the Study Area Because of its strategic geologic and geographic situation in Queensland State, the Bowen-Surat area constitutes one of the more economically significant sedimentary provinces of the Australian mainland and one of the world’s major coal and coal-seam-gas-producing regions. This study considers the Q seam from the Late Permian. Although its thickness varies in the basin because of merging and splitting, it is continuous locally, with an approximate thickness of 5–6 m.

Technology Focus: History Matching and Forecasting (April 2022)

This year’s history matching and forecasting selections, made by reviewer Gopi Nalla of DeGolyer and MacNaughton, reflect the importance of accurate and innovative methodology in the approach toward development of unconventional or challenging plays, from tight oil to highly heterogeneous gas fields to coalbed methane. The authors of paper URTEC 208352 evaluate and compare the performance of rate-normalization and pressure-deconvolution techniques for both synthetic and tight-oil examples. While the synopsis is devoted mostly to the authors’ work in applying these techniques to synthetic cases, much of the complete paper is devoted to tight-oil examples. Ultimately, the authors recommend the pressure-deconvolution approach generally. In paper SPE 207933, the authors apply an integrated approach of using reservoir pressure/gas compressibility (P/Z) calculations to obtain a field gas initially in place (FGIIP) estimation that is then incorporated into an integrated asset model. The technique is applied to a giant onshore gas field. The authors conclude that the new FGIIP estimation can be applied as a reference to re-review the static modeling legacy and to narrow static modeling uncertainties, leading to reliable forecasting and more-efficient field development. An application of the iterative ensemble Kalman smoother to a scenario involving horizontal coalbed-methane wells for a low-permeability field in Australia is the subject of paper URTEC 208291. A forecast study was conducted to validate the history-matched ensemble, with the results showing a good match of 12 months of the new production data not used in history matching, highlighting the robust prediction capabilities of the presented approach. SPE papers continue to a be a vital resource for industry professionals; arguably, such work is more important than ever as the industry and the world adjusts to new modes of collaboration and realities in both the office and the field. I invite you to read the full text of these papers on OnePetro and to find further recent works that advance the literature of this specialized but critical Tech Focus topic. Recommended additional reading at OnePetro: www.onepetro.org. URTEC 208361 - Effect of Relative Permeability on Modeling of Shale Oil and Gas Production by Hamid Behmanesh, University of Calgary, et al. SPE 204835 - Successful Case Study of Machine-Learning Application To Streamline and Improve History-Matching Process for Complex Gas-Condensate Reservoirs in Hai Thach Field, Offshore Vietnam by Son Hoang, Bien Dong Petroleum Operating Company, et al. SPE 207855 - Unleashing the Potential of Relative Permeability Using Artificial Intelligence by Abdur Rahman Shah, Schlumberger, et al.

Gas-phase production equation for CBM reservoirs: Interaction between hydraulic fracturing and coal orthotropic feature

The efficient development of coalbed methane (CBM) reservoirs entails the accurate evaluation of production behavior, particularly for the gas phase performance. However, subjected to complexity arising from the coal inherent heterogeneous properties and dynamic gas-water two-phase flow, pursuit of high prediction accuracy remains challenging. Although massive excellent contributions have been devoted to addressing this issue, several key factors fail to be captured, and in-depth analysis is lacking, involving coal orthotropic feature, as well as associated interaction with hydraulic fractures. In light of the current knowledge status, the research has developed a robust gas-phase productivity equation for CBM wells, putting the emphasis on the coupling influence from coal orthotropic feature as well as hydraulic fracture. Also, gas-water two-phase flow mechanism is captured by incorporating the relationship between pressure and fluid saturation in coal cleat system. Moreover, traditional factors are considered as well, including gas desorption, stress dependence, matrix shrinkage. Numerical simulation is utilized to clarify the reliability of the proposed equation at the stable state, and desirable agreements can be achieved. Results show that (a) Augment effect, induced by enlarging intersection angle, on gas production rate is evident, and the calculation case suggests the optimized angle is 90°, requiring further investigations; (b) The inherent orthotropic feature acts the detrimental role for gas production performance, and fortunately hydraulic fracturing, treated with suitable intersection angle, is able to alleviate the influence; (c) Gas desorption ability lays the profound basis for evaluation of the CBM development, supposed to be selected as the prominent index for the favorable target development area.

High Rank Coal Pore Fracture Structure and its Impact on Reservoir Characteristics in the Southern Qinshui Basin

Although the southern Qinshui Basin is the most successful area for coalbed methane (CBM) development in China, the production of CBM wells in different blocks in the area is significantly different. One of the key reasons is the difference in pore structure in various-ranked coal. In this study, No. 3 coal seam of Sihe and Zhaozhuang blocks in southern Qinshui Basin was selected as the research object to investigate the high rank coal pore fracture structure and its impact on reservoir characteristics. Mercury intrusion porosimetry (MIP), low-temperature liquid nitrogen adsorption (LTN2A), scanning electron microscopy (SEM), and isothermal adsorption tests were conducted. The results show that the Sihe No.3 coal seam was mainly composed of open cylindrical and flat pores with a high proportion of transition pores (10–100 nm), large specific surface area, good connectivity, strong adsorption capacity, high gas content, and reservoir energy. Zhaozhuang No.3 coal had high proportion of mesopores (100–1,000 nm), small specific surface area, poor pores connectivity, weak adsorption capacity, poor gas content, low reservoir energy, and critical desorption pressure. The proportion of cylindrical pores, parallel plate pores, and wedge-shaped pores closed at one end was high. The anomalies in pore morphology and pore structure characteristics of coal reservoir were the main factors that caused variation in gas production of No.3 coal seam in Sihe and Zhaozhuang blocks.

Timeliness Analysis of Coalbed Methane Workover for Reducing Damage to Coal Reservoirs

The workover operations are related to the efficiency of coalbed methane (CBM) and directly decide whether the CBM production target can be achieved. To reduce the damage to the coal reservoir caused by the workover duration, a series of experiments related to the damage to the coal seam by the workover duration, such as permeability experiment, stress–strain experiment, velocity sensitivity experiment, and stress sensitivity experiment, was carried out. The results show that the permeability of the coal sample increases first and then declines with the increase of the immersion time and the changed rate of coal samples is unbalanced. The permeability of the coal sample begins to decrease after 384 h of immersion. The mechanical properties of the coal sample did not change much when the water immersion time was short, but it showed a zigzag change when the water immersion time increased, and the stress–strain peak appeared earlier after 384 h of water immersion, and the elastic modulus became smaller. The consequences of stress sensitivity experiments show that the longer the immersion time, the weaker the recovery of permeability after pressure relief; especially after 384 h, the recovery of permeability is even weaker. Speed sensitivity test results show that the degree of damage to the sensitivity of the coal sample is moderate, but when the coal sample is immersed in water for more than 96 h, the permeability damage is generally greater than that of the dry coal sample. The experimental results prove that the effect of the workover duration has a significant impact on coal reservoir damage, and the workover duration is reasonably arranged. If we can make use of the phase characteristics of physical property changes of coal samples under different immersion times and complete the workover operation in the most appropriate time, then the coal reservoir can be well transformed, and it is possible to obtain good results. Both the production efficiency and production volume of CBM wells will increase.

Analysis of low production coalbed methane wells and application of secondary reconstruction technologies

Analysis of low production coalbed methane wells and application of secondary reconstruction technologies

Numerical Simulation Study of the Upper Aquifer Impact on the Coalbed Methane Production

The coalbed methane (CBM) resources in the Qinshui Basin are abundant with exceptional production potential. Coalbed methane wells usually need to be hydraulically fractured to build economical production. However, the exploration and production experiences have shown that the penetration distances of hydraulic fractures in the vertical direction of coal seams are uncertain, which may lead to fracture communication of the layers above and beneath aquifer layers, resulting in divergent production dynamics among coalbed methane producers. It has been observed that some of the CBM wells in Block M produced significantly more water than other wells in the surrounding area. It is suspected that the hydraulic fracturing among these producers may have communicated to the sandstone aquifers. To address the above challenge, this study investigated the geological characteristics of the aforementioned aquifer and coalbed layers, established a three-dimensional geological model, applied numerical simulation to quantify the influence of the aquifer on the production of the CBM wells, and developed a method to improve the history matching of CBM production simulation with the influence of the aquifer considered. This method has significantly improved the accuracy of the history matching performance and the reliability of the remaining gas study. The results from this study laid the foundation for the subsequent development strategy optimization.

Geological and engineering controls on the differential productivity of CBM wells in the Linfen block, southeastern Ordos Basin, China: Insights from geochemical analysis

In view of the differential productivity of coalbed methane (CBM) wells in the Linfen block on the southeastern margin of the Ordos basin, geochemical analysis is performed to determine the hydrodynamic condition of coal reservoirs, identify the water and gas source of commingled wells, reveal different pressure drop mechanisms, and finally clarify the geological and engineering controls on the production performance. The positive correlations between average daily gas production and the concentrations of Na+, Cl‾, TDS, Sr, and Ba imply that strong hydraulic closure is the premise of high productivity. There is no obvious relationship between water and gas production. Commingled (5 + 8#) wells tend to produce more water than single-layered (5#) wells, because the No. 8 coal seam has more active hydrodynamic condition, which is proven by the lighter δ2H and δ18O and smaller Sr/Ba ratio of waters from commingled wells. The difficulty in pressure drop funnel expansion is the primary constrains for the single-layered wells, which is only resolved by the horizontal wells located in low structural positions at present characterized by increasing trends of TDS, Na+ and Cl‾ contents during drainage. The faster the ion concentration rises, the faster the pressure drop funnel expands and a high peak daily gas production can be quickly achieved. The L-shaped horizontal well is thought to be the most suitable well type due to its high gas yield, low time investment and engineering cost. Due to hydrodynamic heterogeneity, commingled wells often show strong interlayer interference and a change in the water-producing horizon from 5# to 8# coal, which is manifested in the tendency of Cl‾, Na+, and TDS to increase first and then decrease. By selecting superior lithologic assemblages and avoiding strong aquifers, relatively continuous and stable production of commingled wells can also be achieved. This study provides a basis for the further development of CBM in the Linfen block and enriches engineering geochemistry theory.

Drainage Type Classification and Key Controlling Factors of Productivity for CBM Wells in the Zheng Zhuang Area, Southern Qinshui Basin, North China.

The production of coalbed methane (CBM) wells varies greatly in the Qinshui Basin, North China. Analyzing the primary factors controlling the CBM well productivity is essential to improve their development efficiency. Based on the geological conditions and production data of CBM wells in the Zheng zhuang area, the principal component analysis (PCA) method was used to classify the drainage types and screen the key factors influencing the production of gas and water. The drainage types of the CBM wells in the study area can be divided into four categories. The gas production shows an increasing trend with the increase of the comprehensive score of the PCA. The key controlling factors of productivity for CBM wells can be summarized by the gas-bearing property, permeability, groundwater fluid potential, and burial depth. The impact of burial depth on CBM well productivity is manifested in its control of gas content and permeability. The groundwater flows to a low fluid potential area, which leads to a high water production and a small pressure drop. The gas production shows a positive correlation with post-fracturing permeability. The gas content is a key factor for controlling the critical desorption pressure, critical gas production pressure, and pressure drop at the gas breakthrough point. High gas content is a prerequisite for the high productivity of CBM wells.

Geothermal anomalies on the eastern flank of the Cherokee basin, southeastern Kansas, USA

Bottomhole temperature measurements from oil and gas drilling in southeastern Kansas on the eastern flank of the Cherokee basin, in combination with a suite of about 2,200 differential temperature logs recently obtained from wireline logging in coalbed methane wells, define several higher-temperature anomalies at the top of the Mississippian Subsystem strata. Temperatures slightly in excess of 90 oF (35 oC) at depths of about 900 ft (275 m) correspond to geothermal gradients as high as about 60 oC/km.&#x0D; Sparse historical measurements of heat flow in the cratonic Cherokee basin indicate that the thermal anomalies are not likely caused by locally high heat flow. Heat flow in the Cherokee basin is probably in line with most other shallow cratonic basins. The higher-temperature thermal anomalies defined by logging temperatures do not correspond to previously mapped faults or other structural features in the Phanerozoic sedimentary section, but some anomalies are underlain by Precambrian basement lineations that are detectable with aeromagnetic and gravity measurements. Well-log determination of shale content in the Pennsylvanian sedimentary strata overlying the Mississippian limestones indicates that low thermal conductivity caused by higher shale content may cause some of the thermal anomalies. &#x0D; Lateral (advective) movement of warmer, highly saline water from the basin axis cannot account for the anomalies because the anomalies are not characterized by exceptionally highly saline water in Mississippian strata. Similarly, recorded static fluid levels of wells disposing of oilfield saltwater into the Mississippian strata and the deeper Cambrian-Ordovician Arbuckle Group indicate that the deeper Arbuckle strata generally do not have sufficient formation pressure to force Arbuckle formation water upward into the Mississippian through either natural fractures or leaky wellbores. Small-scale changes in salinity, in combination with geologic structuring indicating faulting, make a case for vertical (convective) movement of heated, less saline water from the Arbuckle Group into overlying Mississippian limestones in isolated localities. Buoyancy of the Arbuckle formation water (due to temperature and salinity differences with the cooler and more saline Mississippian water) could also be the primary force behind the convection. Convergence of cooler freshwater moving westward off the Ozark dome and more saline basinal water moving eastward also could be a factor in defining the limits of some thermal anomalies.

Daily production prediction for coalbed methane based on Bayesian temporal matrix factorization

Effective and accurate daily production prediction of coalbed methane (CBM) is significant for enhancing CBM recovery and developing economic evaluations of CBM exploitation. As production time increases, CBM well data gradually show some characteristics of big data and is susceptible to incomplete data and noise data. Traditional geological modeling, however, requires a variety of input factors. In the present study, we apply a time series analysis method based on Bayesian temporal matrix factorization (BTMF) without the deletion of exceptional values to investigate the characteristics of CBM development. In addition, different from the widely used data preprocessing, we innovatively scale the multidimensional data to accomplish the analysis and prediction of different attributive data. By studying the temporal and attributive characteristics of the CBM production curve, the model is applied to a CBM block in China to impute the production data and perform a multi-step rolling prediction of daily gas production.Evaluation metrics, including the mean absolute percentage error (MAPE) and the root mean square error (RMSE), are applied to evaluate the performance. It is found that the imputation by the application of BTMF achieves highly satisfactory estimates (in all tested CBM wells, the maximum MAPE and RMSE are 0.1182 and 245.5882, respectively) and is comparable to the other factorization models. Results also show that BTMF is able to account for the variance in gas production with different multi-step rolling predictions and different predicting scenarios, with the MAPE matrix of five CBM wells of different predicting strategies varies from 0.051 to 0.208, 0.121 to 0.307, 0.099 to 0.221, 0.062 to 0.224 and 0.054 to 0.135, respectively. Because of the similar mechanisms of CBM development, this method can provide a reference for predicting the daily gas production of other CBM wells.