Daily Gas Production Research Articles

Effects of Coal Permeability Anisotropy on Gas Extraction Performance

To investigate gas flow characteristics in coal seams with strong anisotropy, a coupled anisotropic dual-porosity model was established. Effects of permeability anisotropy on variations in gas pressure, gas extraction volume and effective extraction areas were analyzed. Furthermore, mechanisms of crustal stress, initial gas pressure, ultimate adsorption strain and Langmuir volume constant on permeability anisotropy and extraction amount were studied. Results show that permeability anisotropy could result in an elliptical pressure drop zone around production boreholes. Changes in effective gas extraction areas are divided into three stages: slow growth in an elliptical shape, rapid growth with a superposition effect and steady growth in a funnel shape. Permeability isotropy enables faster reaching of stage III than the anisotropy case. As the vertical stress increases, gas pressure distribution around boreholes gradually changes from an ellipse with horizontal direction as long axis to a circle. Larger initial gas pressure could bring consistently higher gas production in the initial and middle extraction stages, and a faster decrease in the late phase. When gas pressure is 2.5 MPa, the peak daily gas production in initial extraction stage is about three times higher than that in the late phase. Ultimate adsorption strain is positively correlated with permeability change. This relationship becomes more significant with a longer extraction time. In contrast, permeability variation is inversely proportional to the Langmuir volume constant in the initial extraction stage. However, these factors are directly proportional in the late stage. The order of significance of each factor’s effect on permeability is crustal stress > ultimate adsorption strain > initial gas pressure > Langmuir volume constant. Moreover, initial gas pressure has the most significant effect on gas extraction volume, while Langmuir volume constant has the least significant impact. Results could provide a theoretical reference for extraction borehole design and drainage parameter setting to improve extraction performance.

Sensitivity analysis of the main factors controlling the potential volumetric evaluation of natural gas hydrate resources in the South China Sea

The China Geological Survey successfully completed the second trial of natural gas hydrate (NGH) production in 2020, and the daily gas production and total gas production were greater than those in the first trial, but the evaluation of NGH resources in the South China Sea (SCS) is still in the evaluation stage, specifically for the gas content. In 2021, some scholars used different methods to more accurately evaluate NGHs in the SCS to aid in NGH exploration and evaluation in the SCS; some of them analysed the main factors controlling NGH resources, added several factors to the volume method for optimization, studied the sensitivity of the evaluation of resources to each of the main controlling factors (NGH stability zone area, NGH area coefficient, NGH stability zone thickness, NGH thickness coefficient, NGH reservoir porosity, NGH reservoir saturation, NGH volumetric ratio, NGH resource ratio coefficient and NGH recovery coefficient) and found that the effective thickness coefficient, effective thickness and effective area coefficient are the most sensitive; these values are 23.15%, 15.66%, 13.98%, and 13.95%, respectively, while the other values are 0%, 15.66%, 8.42%, 8.41%, 2.50%, and 13.92%; taking into account the influence of the main controlling factors, the range of the water resource potential evaluation results in the SCS is 2.4 × 107 m3–5.9 × 1014 m3, the modal value is 7.25 × 1011 m3, and the confidence level of the modal ±25% interval is 77.8%; these values provide a higher evaluation accuracy and higher resource level, which is consistent with the current results of NGH research in the SCS. Although the development of NGHs in the SCS is progressing rapidly, basic exploration is relatively scarce, and the number of samples of effective thickness obtained through dozens of exploratory wells is too few. It is recommended that China carry out more exploration and research projects in the Shenhu area and the entire SCS to obtain more accurate thickness data.

Effects of biogas slurry reflux mode and reflux rate on methane production by mixed anaerobic digestion of corn straw and pig manure

Biogas slurry reflux is a promising method to realize biogas slurry reduction and improve biogas production performance of anaerobic digestion. The purpose of this study was to investigate the effects of reflux mode and reflux ratio on mixed anaerobic digestion of corn straw and pig manure to obtain the best biogas slurry reflux process. The influence of reflux mode and reflux ratio on the internal environment during anaerobic digestion were clarified by kinetic analysis. The results showed that compared with the control group, the degree of substrate hydrolysis in the hydrolysis phase reflux (HPR) and two-phase synergistic reflux (TPSR) treatment groups increased, and the initial concentration and peak value of volatile fatty acids (VFAs) increased by 20.35%–85.81% and 24.72%–74.37%, respectively. The modified Gompertz model fitting results that the three biogas slurry reflux modes all significantly shortened the lag period of anaerobic digestion (17.29%–48.32%) and increased the peak gas production (7.54%–88.07%). And the maximum daily gas production (65.82 mL/(g VS∙d)), methane production (422.86 mL/g VS) and biodegradation rate (83.65%) were obtained under the TPSR mode with reflux ratios of 75% and 100%. This study provides a theoretical basis for the development of biogas slurry reflux technology in the mixed anaerobic digestion of corn straw and pig manure, and realizes the reduction and resource utilization of biogas slurry.

The Effect of Biochar Particle Size on Biogas Production Using Bread Waste Substrate

The effect of biochar supplementation with different particle size on biogas production in two-stage anaerobic digestion of white bread waste was carried out on a laboratory scale using a 100 mL bioreactor. The supplementation of biochar variations with particle sizes <63 µm, <125 µm, <149 µm, <250 µm, and <500 µm and the addition of different biochar concentration of 5 g/L, 15 g/L, and 25 g/L were investigated to obtain optimal concentrations. Mixed cultures were incubated at 35 °C for 40 days. Daily gas production, pH and Chemical Oxygen Demand (COD) were measured using the daily water displacement method. The results showed that the particle size of biochar < 500 µm with a biochar concentration of 5 g/L increased biogas production by 60% and resulted in gas accumulation of 4,240.03 mL/L. CH4, It has proven that biochar increased pH in the mixture. COD concentration decreased from 9,670 mg/L to 1,640 mg/L.

Numerical Simulation of a Class I Gas Hydrate Reservoir Depressurized by a Fishbone Well

The results of the second trial production of the gas hydrate reservoir in the Shenhu area of the South China Sea show that the production of a gas hydrate reservoir by horizontal wells can greatly increase the daily gas production, but the current trial production is still far below the minimum production required for commercial development. Compared with a single horizontal well, a fishbone well has a larger reservoir contact area and is expected to achieve higher productivity in the depressurization development of gas hydrate reservoirs. However, there is still a lack of systematic research on the application of fishbone wells in Class I gas hydrate reservoirs. In this paper, a grid system for gas hydrate reservoirs containing fishbone wells is first established using the PEBI unstructured grid, and fine-grained simulation of reservoirs near the bottom of the wells is achieved by adaptive grid encryption while ensuring computational efficiency. On this basis, Tough + Hydrate software is adopted to simulate the productivity and physical field change of a fishbone well with different branching numbers. The results show that: the higher the number of branches in a fishbone well, the faster the free water production rate, reservoir depressurization, and free gas production rate in the initial stage of depressurization development, and the faster depressurization can effectively promote hydrate dissociation. Compared with a single horizontal well, the cumulative gas production of a six branch fishbone well can increase by 59.3%. Therefore, using multi-branch fishbone depressurization to develop Class I gas hydrate reservoirs can effectively improve productivity and the depressurization effect, but the hydrate dissociation will absorb a lot of heat and lead to a rapid decrease in reservoir temperature and hydrate dissociation rate. At the end of the simulation, the hydrate dissociation rate of all schemes was lower than 50%. In the later stage of depressurization development, the combined development method of heat injection and depressurization is expected to further provide sufficient thermal energy for hydrate dissociation and promote the dissociation of the hydrate.

Design of a prediction model based on improved BP neural network and particle swarm optimization for more accurate budget of biogas production

In order to accurately predict the daily gas production of large and medium-sized biogas projects, the improved BP neural network algorithm was used, and the PSO algorithm was introduced to optimize the parameters. According to the anaerobic fermentation mechanism and the actual engineering operation status, a prediction model was established with temperature, daily feed volume, NH3, TS concentration and pH value as input layer nodes, and daily biogas production as output layer nodes. The 116 sets of data obtained by remote data acquisition are used as training samples and test samples of the model, and the simulation is carried out by Matlab software. The results show that the PSO-LM-BP neural network has good predictive ability for the daily gas production of biogas. The established biogas daily gas production prediction model not only converges fast but also has high accuracy.

Geological adaptability of deep CBM fractured horizontal well in SLN block

The buried depth of the main coal beds in SLN Block is more than 1,500 m, and the gas content of the coal beds is high. However, the coal beds are generally in a high geostress environment, the permeability of the coal beds is generally low, and the development effect of conventional fractured straight wells is poor. Fractured horizontal well is an important technical means to improve the development effect of low permeability coalbed methane, but the investment cost is high. To reduce the investment risk of fractured horizontal wells, it is necessary to find out the gas production capacity and main control factors of the fractured horizontal wells, and determine the area suitable for the development of fractured horizontal wells. In the area with permeability higher than 0.28 md and gas content higher than 12.8 m3/t, the daily gas production capacity of fractured horizontal well is 16,450–21500 m3/d, and the development effect is good. The research results are of great significance to quickly evaluate the adaptability of fractured horizontal wells.

Economic Value Estimation of Biogas Utilization in Public Wastewater Treatment Plants of the Republic of Korea

This paper presents economic value estimation of improved biogas utilization systems of public wastewater treatment plants in Republic of Korea. Since a large amount of biogas produced at digestion facilities is being wasted as a by-product, the biogas energy utilization system needs to be enhanced. In this paper, three operating options able to utilize the produced biogas are proposed, and then their monetary benefits are estimated by means of net present value calculation. Real operational data from the public wastewater treatment plant located in Sejong city, Republic of Korea, is used to reflect a variation of the rated daily gas production and its concentration according to the weather and seasons, resulting in calculating more reliable results. Additionally, to minimize the estimation errors due to uncertainties of the gas concentration and the gas selling price, a Monte Carlo simulation considering the variation of critical input data is carried out. As a result, the proposed approach can lead to better decisions in selecting the suitable biogas utilization system by forecasting the ranges of possible economic values.

Depressurization-induced gas production from hydrate reservoirs in the Shenhu sea area using horizontal well: Numerical simulation on horizontal well section deployment for gas production enhancement

In 2020, China successfully conducted the second round of natural gas hydrate pilot production with horizontal wells at W11-W17 deposits in the Shenhu sea area of South China Sea, but the average daily gas production is far from reaching the commercial exploitation. Low productivity has become one of the key factors hindering the commercial exploitation of gas hydrate reservoir. This work taking SHSC-4 well as an example, uses numerical simulation method to analyze the impact of the placement of horizontal well section, length and the production system on productivity of horizontal well in depressurization exploitation. From the analysis of simulation results, it can be seen that the best performance of production capacity can be achieved when horizontal section placed in layer II, which is compared with that placed in layer I and III. More importantly, hydrate in layer I and free gas in layer III can be effectively utilized to improve productivity when layer II is exploited. When the horizontal section is arranged in layer II and produced by depressurization with small pressure difference (1 MPa), the longer the horizontal section length is, the better the productivity will be. However, the average cumulative gas production increment per meter is gradually decreasing. According to the simulation results, 300 m is a reasonable horizontal section length for the exploitation of layer II, and the cumulative gas production reaches 2.55 million cubic meters after 60 days of continuous exploitation. In addition, due to the limitations of convective heat transfer in the low-permeability reservoir in the Shenhu sea area, sensible heat can significantly improve the secondary hydrate generated in the wellbore and the reservoir around the wellbore due to throttling expansion effect, which has a good effect on productivity improvement. Compared with the situation without heating, when the horizontal section is arranged in layer II and the length is 300 m, the production mode of depressurization and combined heating is adopted, and the cumulative gas production of 60 days with different pressure difference (1–5 MPa) is 0.14, 5.55, 14.75, 23.72, and 29.5 times higher than that without heating.

Characteristics of In Situ Stress and Reservoir Pressure in Deep Coal Seams and Their Influences on Reservoir Depletion: A Field Case Study

The production of coalbed methane resources is greatly dependent on the reservoir depletion process. To improve the depressurization efficiency of deep coalbed methane (DCBM) reservoirs, the fluid production characteristics and implications of in situ stress and reservoir pressure for reservoir depletion in the eastern margin of the Ordos Basin are analyzed. The results indicate that the duration of the single-phase water production stage is overall long, with the gas declining stage occurring too early. The daily gas production volume of DCBM wells is only a few hundred m3. For DCBM reservoirs, it is considered that in situ stress, initial reservoir pressure, and critical desorption pressure significantly affect the fluid production and depressurization process. A high in situ stress in deep coal seams is likely to damage the flow conductivity of fracture systems due to the increase in effective stress during reservoir depletion. Based on the in situ stress characteristics of deep coal seams and their implications for reservoir depletion, we propose that the depressurization of DCBM reservoirs during gas production can be promoted via a new method of stress release. Slots or cavities created in coal seams by high-pressure hydraulic jet can provide space for stress release. This novel depressurization method could help improve the gas production efficiency of DCBM reservoirs.

Gas and water performance from the full-cycle of coalbed methane enrichment-drainage-output: A case study of Daning-jixian area in the eastern margin of Ordos Basin

Coalbed water (CBW), as a stratigraphic fluid, is stored and transported together with coalbed methane (CBM), and has an important influence on the generation, transport, enrichment and production patterns of CBM. In order to study the interaction mechanism between CBM and CBW in the full cycle of CBM enrichment-drainage-output, we collected CBW samples from typical wells at different production times and development data of CBM wells in Daning-jixian area in the eastern margin of Ordos Basin. According to the geochemical test results of CBW samples and the main parameters of 5# coal seam, the basic characteristics of CBW in the study area were analyzed. Then, the control of hydrochemical field on CBM enrichment, the influence of hydrodynamic field on CBM drainage, and the connection between CBW evolution and gas production were discussed, respectively. The results show that in the low burial depth area of the 5# coal seam in the monoclinic structure, the ion concentration of CBW is higher, and the Cl–Na coefficient, desulfurization coefficient and carbonate equilibrium coefficient are relatively small, making it a relatively enriched area for CBM. CBM production in high hydrodynamic areas has a greater need for drainage and depressurization, and the average daily gas production is relatively small. The evolution in daily gas production and the hydrochemical characteristics of CBW during CBM drainage show a good correlation. Every increase in gas production is accompanied by an increase in TDS and a decrease in Cl–Na​ coefficient, desulfurization coefficient and carbonate equilibrium coefficient in the extracted water.

A deep learning model for predicting the production of coalbed methane considering time, space, and geological features

Coalbed methane (CBM) is high-quality clean energy and accurate prediction of daily gas production of CBM is critical for CBM engineering. However, the production process of CBM is a non-stable dynamic with significant fluctuation, and it is hard to predict by traditional statistical methods. This study processes a deep learning model T-DGCN considering time, space, and geological features for predicting complex long gas production sequences. T-DGCN innovatively measures the similarity of geological features between wells with Dynamic Time Warping (DTW), and merges geological and spatial features to dynamically correct the weight matrix in a multilayer neural network with multiple aggregations. Then, the model uses the Gated Recurrent Unit (GRU) to extract the temporal features of gas production and predict the daily gas production sequence. The experiments with the data set from Shanxi Province showed that T-DGCN achieves an accuracy of 0.9298 in short-term production prediction, which is higher than the baseline models. In addition, the geological similarity calculated by DTW in T-DGCN significantly improves the performance of the model. And T-DGCN can still have better performance in long-term prediction tasks with accuracy above 0.9. This study provides a new method for the theoretical guidance for adjusting development schemes of CBM and the prediction of long-time series in geoscience.

Study on Double Pressure Funnels and Gas-Liquid Two-Way Mass Transfer after Fracturing in Shale Gas Reservoirs

Well shut-in and drainage after shale gas fracturing are important factors affecting the productivity. Due to the imperfect optimization method of shale gas flowback, there has been no clear explanation for the problems such as “formulation of reasonable well shut-in time” and “less fracturing fluid flowback but high-gas production phenomenon” during shale gas drainage. In this paper, the double pressure funnels (one funnel is formed during fracturing by pressure difference from wellbore to formation, and two funnels are formed during flowback by pressure difference from fracture to formation and from fracture to wellbore) and gas-liquid two-way mass transfer (gas transfer by diffusion and liquid transfer by pressure difference) in shale gas drainage are investigated by calculating the pressure distribution after fracturing shale gas wells. The discrete numerical simulation by using unstructured PEBI grid is conducted, and the result is as follows: when shale gas well is shut-in for 20 days and produce for 1 year, the daily gas production corresponding to fracturing fluid flowback rates of 20%, 10%, and 5% are 47700 m3, 5800 m3, and 72700 m3, respectively. The investigation of double pressure funnels and gas-liquid two-way mass transfer explains clearly the phenomenon “less fracturing fluid flowback but high-gas production.” Meanwhile, the two conditions for optimizing the well shut-in time after fracturing are presented. That is, as for the studied case, the moving speed of the pressure boundary line should be less than 0.1 m/d, and the water-gas ratio near the fracture should be less than 1 / d with time. Consequently, the reasonable well shut-in time is optimized to be 20-25 days. The findings in this work are of benefit to enrich the flowback theory of shale gas after fracturing and provide a theoretical basis for the optimization technology of shale gas drainage after fracturing.

Optimized long short-term memory (LSTM) network for performance prediction in unconventional reservoirs

Unconventional resources play an increasingly important role in the global energy supply. Performance prediction is crucial for adjusting development methods in unconventional reservoirs to ensure high production. However, daily production prediction of tight gas wells relies on many factors and complex variation patterns exist, which makes it difficult to predict using conventional methods. Therefore, this study proposes a hyper-parameters optimized long short-term memory (LSTM) network to effectively forecast daily gas production. Bayesian optimization is adopted to optimize the essential configuration of the LSTM. The model is trained by five features (wellhead tubing pressure, wellhead casing pressure, reservoir temperature, water production and gas rate) for seventy-five tight gas wells in the Ordos Basin, China, and is then validated on a test dataset with six wells in the same region. The average mean square error (MSE) of the test dataset is as low as 0.006, which indicates high prediction accuracy. Compared with cases with different input features, the five-feature case provides the most stable result for time-series performance prediction. We then comprehensively evaluate the daily gas production prediction of the LSTM network, including verifying it with the auto-regression integrated moving average (ARIMA), the artificial neural network (ANN), and the standard recurrent neural network (RNN). The results demonstrate that the optimized LSTM network can handle sequential data with time-series dependencies to improve the accuracy of performance prediction.

Pore structure and fractal characteristics of marine-continental transitional shales in the southern North China Basin

Research on marine-continental transitional shale in China is significant because this type of shale contains rich gas resources. The shale pore development, which is the key factor in determining the reservoir gas-bearing capacity, is complex. The organic matter (OM) content of the Shanxi and Taiyuan Formations shale in the southern North China Basin is medium to high, the mineral composition differs from that of other transitional shales, and the quartz content is higher than the clay content. The OM content and mineral composition exhibit a strong longitudinal heterogeneity. The pore types are mainly inorganic pores, and OM pores are less developed. The pore morphology is mainly parallel plate-like fissure pores, and there are a few ink-bottle-like pores composed of micro- and macropores. The specific surface area and total pore volume (TPV) of mesoporous-macropores are mainly controlled by mesoporous. The micropore volume is mainly controlled by micropores with sizes below 1.2 nm. Pore structure parameters and fractal dimension find that Shanxi and Taiyuan Formations shale has complex pore structure and rough pore surface. The fractal dimension D2 more accurately characterizes the roughness of the micropore surface. Compared with other shales, the micropore surface roughness of Shanxi and Taiyuan Formations shale is lower. The fractal dimensions and TPV do not correlate. The pore morphology and mineral characteristics of Shanxi and Taiyuan Formations shale leads to relatively low gas adsorption capacity and strong gas storage capacity, and is favorable for oil and gas migration. Due to the effects of compaction, macropores formed by quartz break and are filled with clay, resulting in a low daily gas production of the transitional shale in well MY1 after fracturing. The results provide references for the optimization of favorable reservoirs and the prediction of enrichment areas during transitional shale gas exploration.

Effect and mechanism analysis of resonance on physical parameters of unconventional reservoirs

Inducing shale reservoir resonance is an environmentally friendly and efficient unconventional oil/gas production technology. It is necessary to study the effect of resonance on shale physical parameters. This paper clarifies the resonance mechanism of improving shale reservoirs and constructs the natural frequency parameter equation under a single excitation direction using vibration system theory and rock mechanics. The resonance experiment is carried out after the physical parameters of the shale and coal samples are verified by material characterization technology. Meanwhile, CT scanning technology and matrix permeability tests are used to measure the samples’ pore development and permeability changes. Eventually, the coalbed methane field in Qinshui Basin, Shanxi province, was selected as the experimental object for the reservoir resonance test. We analyzed the production data of the test wellhead. The results indicate that the mechanism of resonance improvement of shale physical parameters promotes the redevelopment of primary cracks in the rock mass; the porosity and permeability of rock mass are increased by 2–12 times and 2–8 times, respectively, after the once resonance test. The CBM (coalbed methane) wells whose productivity is in a state of decay have been significantly enhanced after resonance stimulation, and the relative daily gas production is increased by 101.61%.

Improving the production efficiency of high rank coal bed methane in the Qinshui Basin

There are abundant high-rank coal bed methane (CBM) resources in China, accounting for one third of total CBM resources. Its efficient development and utilization is of great significance to guarantee the national energy strategic security, diminish the hidden danger of coal mine production and reduce carbon dioxide emission. In order to solve the "four lows" problem (i.e., low effective utilization ratio of proved reserves, low productivity targeting ratio, low single-well production rate and low development profit) restricting the development of high-rank CBM industry in China, this paper deeply analyzes the core problems restricting the development of high-rank CBM. Based on this, several new methods of production control, area selection and evaluation are put forward by taking multiple measures, such as paying the same attention on theoretical research and technological research & development, carrying out laboratory research and field test in parallel and conducting large-scale construction and benefit development simultaneously. And the following research results are obtained. First, the geological difference between CBM and coal mine, the difference in reserves recoverability, the adaptability of engineering technology and the scientificity of production are the main factors restricting CBM development effect. Second, "Four-element" production control theory, methane-leading engineering transformation method and methane-leading production control theory are proposed, which provides guidance for the development of a series of technologies for the efficient development of high-rank CBM. Third, in practice, the control degree of quality reserves is increased from 32% to 80%, the success ratio of development wells is increased from 60% to 95%, the average single-well daily gas production of vertical wells is increased by about 1100 m3, the drilling cost of horizontal wells is reduced by 50%, and the operation cost per cubic meter of gas is reduced by 24%. In conclusion, the established technology series for the efficient development of high-rank CBM actively promote the efficient CBM development in the Qinshui Basin. The yearly CBM production of PetroChina Huabei Oilfield Company is expected to reach 20 × 108 m3 in the middle of the "14th Five-Year Plan", which promotes the strategic development of CBM industry in China.

A method for identifying coalbed methane co-production interference based on production characteristic curves: A case study of the Zhijin block, western Guizhou, China

Efficient detection of coalbed methane (CBM) co-production interference is the key to timely adjusting the development plan and improving the co-production efficiency. Based on production data of six typical CBM co-production wells in the Zhijin block of western Guizhou Province, China, the production characteristic curves, including production indication curve, curve of daily water production per unit drawdown of producing fluid level with time, and curve of water production per unit differential pressure with time have been analyzed to explore the response characteristics of co-production interference on the production characteristic curves. Based on the unit water inflow data of pumping test in coal measures, the critical value of in-situ water production of the CBM wells is 2 m3/(d·m). The form and the slope of the initial linear section of the production indication curves have clear responses to the interference, which can be used to discriminate internal water source from external water source based on the critical slope value of 200 m3/MPa in the initial linear section of the production indication curve. The time variation curves of water production per unit differential pressure can be divided into two morphological types: up-concave curve and down-concave curve. The former is represented by producing internal water with average daily gas production greater than 800 m3/d, and the latter produces external water with average daily gas production smaller than 400 m3/d. The method and critical indexes for recognition of CBM co-production interference based on the production characteristic curve are constructed. A template for discriminating interference of CBM co-production was constructed combined with the gas production efficiency analysis, which can provide reference for optimizing co-production engineering design and exploring economic and efficient co-production mode.

Hydrocarbon accumulation model influenced by “three elements (source-storage-preservation)” in lacustrine shale reservoir-A case study of Chang 7 shale in Yan’an area, Ordos Basin

The organic-rich shales of the Chang 7 Member in the Yan’an Formation of the Yan’an area, Ordos Basin is a hot spot for lacustrine shale gas exploration. In this paper, taking the Chang 7 Member shale in the Yan’an area as an example, the main controlling factors of lacustrine shale gas accumulation and the prediction of “sweet spots” are systematically carried out. The results show that the Yanchang Formation shale has the complete gas generating conditions. Shale gas accumulation requires three necessary accumulation elements, namely gas source, reservoir and good preservation conditions. The dynamic hydrocarbon generation process of the Chang 7 shale reservoirs is established according to the thermal simulation experiments of hydrocarbon generation, and the mechanism of catalytic degradation and gas generation in the Chang 7 Member under the background of low thermal evolution degree is revealed. The enriched authigenic pyrite can catalyze the hydrocarbon generation of organic matter with low activation energy, thereby increasing the hydrocarbon generation rates in the low-mature-mature stage. Different types of pores at different scales (2–100 nm) form a multi-scale complex pore network. Free gas and dissolved gas are enriched in laminar micro-scale pores, and adsorbed gas is enriched in nano-scale pores of thick shales, and silty laminates can improve the physical properties of the reservoir. This is because the laminar structure has better hydrocarbon generation conditions and is favorable for the migration of oil and gas molecules. The thickness of the lacustrine shale in the Chang 7 Member is between 40 and 120 m, which has exceeded the effective hydrocarbon expulsion thickness limit (8–12 m). At the end of the Early Cretaceous, the excess pressure of the Chang 7 shale was above 3 MPa. At present, horizontal wells with a daily gas production of more than 50,000 cubic meters are distributed in areas with high excess pressures during the maximum burial depth.

Coalbed methane reservoir dynamic simulation comparisons using the actual steeply inclined model and ideal steeply inclined model

Numerical simulation is an efficient method to quantitatively describe the reservoir dynamics of coalbed methane (CBM) reservoirs. The ideal steeply inclined model (ISIM), assumed to be a steeply inclined plate, has been widely applied in steep coalbed methane reservoir modeling, although the ISIM cannot accurately reflect the actual reservoir geological conditions. In this paper, the dynamics of CBM production and reservoirs using the ISIM and actual steeply inclined model (ASIM) were compared, taking the steep coal in the Fukang mining area located in northwestern China as an example, with the purpose of revealing the differences and applicability of the ASIM and ISIM. The ASIM and ISIM were established by Petrel software, and CBM production was matched and predicted by Eclipse software. Data reflecting reservoir dynamics, such as water saturation, reservoir pressure, and gas content, were extracted. The dynamic changes in the reservoir physical properties of the ASIM and ISIM were also compared. The results showed that: 1) multiple gas production peaks occurred in both ASIM and ISIM. The maximum daily gas production of ASIM occurred earlier than the maximum daily gas production of ISIM. The peak gas production and cumulative gas production of ASIM were both greater than the peak gas production and cumulative gas production of ISIM. 2) Due to the variations in grid shape and dip angle with each grid in the ASIM, the production effect of the ASIM was better than the production effect of the ISIM in the third stage (4–10 years) of drainage. 3) In the third stage (4–10 years) of drainage, the decrease rate of reservoir pressure of ASIM was larger than the decrease rate of reservoir pressure of ISIM because of the relatively better production performance of ASIM. 4) Differentiation of gas and water dominated the variation trend of gas content, and in the third stage (4–10 years) of drainage, the ASIM has higher recovery efficiency compared with ISIM. Compared with ISIM proposed by previous scholars, the ASIM was more helpful to monitor the dynamic behavior of coal reservoirs, and ASIM can provide a more reliable basis for guiding coalbed methane development.