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Fracture and cleats development controls the permeability of coal reservoirs, while the migration of coal fines can block fractures and affect coalbed methane (CBM) production performance. To reveal the migration, agglomeration, and settlement of coal fines within fractures, and also to investigate permeability variations, an experimental simulation was conducted. Factors like coal fine particle sizes (<48, 48−75, 75−96, 96−120, and 120−180 μm), fracture width (0.05, 0.10, 0.15, and 0.20 mm), coal fines suspension concentration (0.5‰, 1.0‰, 1.5‰, 2.0‰, and 2.5‰), and injection flow rates (2.5, 5.0, 7.5, and 10.0 mL/min) were considered, and the deposited and output coal fines qualities were recorded. The results showed that by controlling stable injection flow rates, the injection pressures increased with the extension of time, indicating fractures were blocked gradually by coal fines. The pressure variation curves could be divided into three types: (1) steady slow rise type, (2) stable to sharp rise type, and (3) fluctuating type. The quality of deposited coal fines in fractures varied between 0.0068 and 0.917 g, and the quality of output coal fines was between 0 and 0.1028 g. With fracture width incrementation, the deposited and output values of coal fines of different sizes all increased. As coal fines concentration increased, the output values first increased and then decreased, and vice versa for deposited values. When the injection flow rate increased, the deposited coal fines values initially increased and then diminished. In the largest coal fines deposition, an injection flow rate of 5.0 mL/min was observed, while larger and stable coal fines migration and production were observed at 2.5 and 7.5 mL/min. Under most of the circumstances (except for 120−180 μm coal fines), permeability losses were concentrated between 70% and 95%, and the permeability loss with time was concentrated between 0.15 and 0.178 mD/h. Thus, the induced damages of coal fines to fractures were similar and could damage most of the flow channels. The quality of deposited coal fines was positively correlated with permeability reduction. For better coal fines output during CBM production, the flow rate should be controlled at certain rates for stable coal fines migration (e.g., 7.5 mL/min in this study). Also, further research should be focused on the dispersion of coal fines and their precise control.

The Taodonggou group of Middle Permian is an important source rock in Taibei sag of Turpan-Hami basin. Due to its deep burial, drilling has only been revealed in recent years. Based on organic petrology and organic geochemistry experiments, this paper studies the organic petrology, organic geochemistry, sedimentary environment, and hydrocarbon generation potential of source rocks in Taibei sag, Turpan-Hami basin, and reveals the influence of the sedimentary environment on the organic matter abundance of source rocks. The results are as follows: (1) The organic matter of the Middle Permian source rocks in Taibei sag of Turpan-Hami basin is mainly sapropelite and exinite. The vitrinite is mainly vitrodetrinite, and the exinite is mainly lamalginiite. (2) The total organic carbon content value is 0.55–6.08 wt %, and the average value is 2.58 wt %. The PG value ranges from 0.78 mg HC/g to 30.86 mg HC/g, and the average value is 4.88 mg HC/g. Chloroform asphalt “A” is 0.046–0.8767 wt %, and the average value is 0.285 wt %. The types of organic matter are mainly III and II–III, and the R o value is 0.628–1.49 wt % (average = 0.988 wt %). The T max distribution is 329–465 °C. The average temperature is 434.7 °C, which is in the mature stage (oil window stage). The Middle Permian source rocks are mainly very good to excellent source rocks with a good hydrocarbon generation potential. (3) The source rocks are deposited in a semihumid and semiarid climate. Organic matter is input as a mixed source. The early and late stages is dominated by terrestrial higher plants. The middle stage is dominated by lower aquatic organisms, and the sedimentary environment consists of weak reduction and weak oxidation environments. (4) In the study area, the abundance of organic matter has a weak negative correlation with CPI and a positive correlation with Pr/Ph and ∑C21–/∑C22+. Under the coaction of paleoclimate, organic matter input, and redox environment, the enrichment model of organic matter with high productivity and weak oxidation environment characteristics can also form excellent source rocks. This study is of great significance and provides theoretical guidance for the exploration of deep oil and gas resources.

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Coal structure directly correlates to permeability and hydraulic fracturing effects. Underground coal mining indicates that a single coal section generally contains multiple coal structures in superposition, making how to recognise the coal structure combination and predict its influence on coal permeability a challenging problem. Based on well-drilling sampled cores, the geological strength index (GSI), and well-logging data, the DEN, GR, CALX, and CALY were selected to establish a model to predict GSI by multiple regression to identify coal structure from 100 coalbed methane wells. Based on fitting GSI and corresponding permeability test values, injection fall-off (IFO) testing, and hydraulic fracturing results, permeability prediction models for pre- and post-fracturing behaviour were established, respectively. The fracturing effect was evaluated by the difference in permeability. The results show that a reservoir can be classified into one of nine types by different coal structure thickness proportion (and combinations thereof) and the fracturing curves can be classified into four categories (and eight sub-categories) by the pressure curve. Up-down type I and type II reservoirs (proportion of hard coal >60%) and intervening interval type I reservoir (proportion of hard coal >70%) are prone to form stable and descending fracturing curves and the fracturing effects are optimal. Intervening interval type II (hard coal:soft coal:hard coal or soft coal:hard coal:soft coal ≈1:1:1) and up-down type III (hard coal:soft coal =1:1) form descending type II, rising type I and fluctuating type I fracturing curves and fracturing effect ranks second; up-down type IV and V (proportion of hard coal <40%), interval type III (proportion of hard coal <30%), and multi-layer superposition-type reservoirs readily form fluctuating and rising fracturing curves and fracturing effects therein are poor. The research results provide guidance for the targeted stimulation measured under different coal structure combinations.