Deep Coalbed Methane Reservoirs Research Articles

Experimental Analysis of the Mechanical Properties and Failure Behavior of Deep Coalbed Methane Reservoir Rocks

Experimental Analysis of the Mechanical Properties and Failure Behavior of Deep Coalbed Methane Reservoir Rocks

Fluid Spontaneous Imbibition Under the Influence of Osmotic Pressure in Deep Coalbed Methane Reservoir in the Ordos Basin, China

Summary The flowback rate of a hydraulic fracturing fluid is related to coalbed methane (CBM) production in gas wells. The deep (>2000 m) CBM reservoir in the Ordos Basin has an extremely high salinity (>200 000 mg/L), which results in a very low flowback rate of fracturing fluid. The mechanism underlying the extremely low flowback rate of the fracturing fluid remains unclear. This study experimentally simulated two patterns of osmotic pressure variation that exist at a hydraulic fracturing site: the processes of injection of a low-salinity fracturing fluid into a high-salinity reservoir and a high-salinity fracturing fluid into a low-salinity reservoir. Low-field nuclear magnetic resonance (NMR) technology was used to monitor dynamic fluid migration and fluid distribution in the coals. Results showed that osmotic pressure is a driving force for spontaneous imbibition when the salinity of the fracturing fluid is lower than that of the reservoir water, and more fluid enters the coal as the osmotic pressure increases. This causes the displacement of the high-salinity fluid already present in the micropores by the low-salinity fracturing fluid. In high-salinity deep coal seams, both osmotic pressure and capillary forces cause the spontaneous imbibition of the fracturing fluid from fractures into pores, promoting CH4 desorption, alleviating the water-blocking effect, and enhancing the filtration loss of the fracturing fluid. In contrast, the injection of a high-salinity fluid into the reservoir with a low-salinity brine (LSB) creates an osmotic pressure difference that prevents fluid imbibition. In shallow, low-salinity coal seams, the injection of high-salinity fracturing fluids can result in high flowback rates. Therefore, these two injection schemes are significant for an understanding of the role of osmotic pressure in deep CBM extraction and serve as valuable guides for optimizing the selection of the fracturing fluid and improving its effective flowback.

Hydraulic fracture initiation and propagation in deep coalbed methane reservoirs considering weak plane: CT scan testing

Hydraulic fracturing technology in coal reservoirs helps increase coalbed methane (CBM) production, and the development of hydraulic fractures (HFs) is influenced by in situ stress and original fractures. Therefore, in this study, triaxial HF tests and computed tomography (CT) were used to determine HF initiation and propagation in coal, considering weak structural planes and in situ stress. The experimental results show that weak structural planes control HF initiation and propagation in coal under a deep-stress environment. Most HFs occurred along bedding planes, followed by exogenetic fractures. The influence of the horizontal stress difference coefficient k, which is equal to the maximum horizontal stress minus the minimum horizontal stress and divided by the minimum horizontal stress, on the propagation of the HF was studied. When k increases to 1.04, the HF becomes perpendicular to the direction of the minimum principal stress. When k < 1.04, the main controlling factor of HF propagation is a weak structural plane, and when k ≥ 1.04, the main controlling factor of HF propagation is in situ stress. Based on the CT reconstruction model, the average aperture distributions of the discrete bedding fractures and exogenetic fractures of coal in this experiment were calculated to be 0.0947 mm and 0.1940 mm, respectively. This determines the different strength properties of exogenetic fractures and bedding planes, and determines the priority initiation position of HF in coal. During the HF initiation and propagation, the average energy along the exogenous fracture was lower than that along the bedding planes. On this basis, this study predicts that the main factor controlling HF propagation in a deep coal seam in the Qin-Shui Basin, China, is the weak structural plane in the coal seam.

A Semi-Analytical Model for Production Prediction of Deep CBM Wells Considering Gas-Water Two-Phase Flow

The productivity prediction of deep coalbed methane (CBM) wells is significantly influenced by gas-water two-phase flow characteristics and seepage parameters of the fracture network. While numerical simulations offer a comprehensive approach, analytical models are favored for their faster and broader applicability. However, conventional analytical models often oversimplify the complex problem of two-phase seepage equations, leading to substantial errors in dynamic analysis outcomes. Addressing this shortcoming, we establish a gas-water two-phase productivity prediction model for deep CBM reservoirs. This model takes into account the two-phase flow characteristics within the reservoir and fracture network, as well as the stress sensitivity of the reservoir and fractures. Additionally, a modified trilinear flow model characterizes the fractured modification body. By integrating the flowing material balance equation with the Newton Iteration method, we gradually update the seepage model’s nonlinear parameters using the average formation pressure. We also linearize the gas-water two-phase model through successive iterations to derive a semi-analytical solution. The accuracy of the model was verified through comparison with commercial numerical simulation software results and field application. The model also enabled us to scrutinize the influence of reservoir and fracture network parameters on productivity. Our research findings suggest that the semi-analytical solution approach can efficiently address the nonlinear seepage problem of gas-water two-phase flow, enabling quick and accurate prediction of deep CBM well productivity. Moreover, appropriate fracture network parameters are paramount for enhancing the productivity of deep CBM wells. Lastly, during the development of deep CBM reservoirs, it is crucial to control the production pressure difference appropriately to minimize the stress sensitivity impact on production capacity.

Reservoir characteristics and gas production potential of deep coalbed methane: Insights from the no. 15 coal seam in shouyang block, Qinshui Basin, China

Considering the large burial depth and unclear coalbed methane (CBM) development potential of the No. 15 coal seam in the Shouyang block in the northern Qinshui Basin, this study investigated the characteristics and gas production capacity of deep CBM reservoirs in the No. 15 coal seam based on the analysis of geological characteristics of CBM and the simulation of CBM production capacity. The No. 15 coal seam has a large thickness, strong adsorption capacity, medium gas content, low critical desorption pressure, low reservoir pressure, and a low ratio of critical desorption pressure to reservoir pressure (also referred to as the ratio). Based on the reversible relationship between the adsorption and desorption of CBM, we established an equation expressing the relationship between the gas content and burial depth of the No. 15 coal seam using massive data from gas content tests, isothermal adsorption experiments, and well tests. The analyses of main factors controlling the permeability of deep reservoirs of the No. 15 coal seam and their differences with those of shallow reservoirs indicate that deep CBM reservoirs have significantly low permeability owing to their large burial depth and high in-situ stress despite their favorable coal structure and well-developed fractures. Moreover, this study predicted the gas production characteristics of the No. 15 coal seam through numerical simulations of CBM drainage. The simulation results were similar to the actual gas production results, indicating that the No. 15 coal seam has great gas production potential. The results of this study will provide geological support for predicting the gas content and assessing the development potential of the No. 15 coal seam in the deep part of the northern Qinshui Basin.

Nanoscale Pore Structure Characteristics of Deep Coalbed Methane Reservoirs and Its Influence on CH₄ Adsorption in the Linxing Area, Eastern Ordos Basin, China.

The high gas content of deep coal seams is a driving force for the exploration and development of deep coalbed methane (CBM). The nanoscale pores, which are the main spaces for adsorption and storage of CBM, are closely related to the burial depth. Based on integrated approaches of vitrinite reflectance (Ro), maceral composition, scanning electron microscope (SEM), proximate analysis, fluid inclusion test, low-temperature N₂ adsorption-desorption, and CH₄ isothermal adsorption, the nanoscale pore structure of coals recovered at depths from 650 to 2078 m was determined, and its influence on the CH₄ adsorption capacity was discussed. The results show that the coal rank has a good linear relationship with the current burial depth of the coal seams; that is, the influences of the burial depth on the coals can be reflected by the influences of the coal rank on the coals. With the increase in the coal rank, the moisture and volatile content decrease, and the fixed carbon content increases. The variation in the pore volume and specific surface area with the increase in the coal rank can be divided into two stages: the rapid decline stage (when 0.75%<Ro < 1.0%), dominated by the compaction and gelatinization, and the slow decline stage (when 1.0%<Ro < 1.35%), characterized by the low stress sensitivity and the mass production of secondary pores. The percentage of micropores increases throughout the process. When 10 nm is taken as the boundary, the nanoscale pores show different fractal features. When Ro < 1.0%, the fractal dimension (FD) of the micropores is close to 3. When Ro > 1.0%, the FD of the micropores is close to 2. This indicates that with the increase in the degree of coalification, the surface of the micropores is simpler. The above results show that the gas adsorption capacity of coal first slightly decreases (when 0.75% < Ro < 1.0%) and then increases (when 1.0% < Ro < 1.35%), and the coincident results are shown in the Langmuir volume (VL) test results.

Implications of geological conditions on gas content and geochemistry of deep coalbed methane reservoirs from the Panji Deep Area in the Huainan Coalfield, China

The objective of this study is to reveal the implications of geological conditions on gas content and geochemistry of deep coalbed methane (CBM) reservoirs. It is of great practical significances to improve the theory and technology for deep CBM development. In this work, the gas content and geochemistry of selected samples were obtained by canister desorption method, gas chromatography (GC) and GC–Mass Spectrometry (GC–MS). On the basis of geological conditions, the Panji Deep Area was confirmed as a mining block of high gas content, high ground stress and reservoir temperature, multiple sets of coal seams, and complex mining conditions. Deep-buried coals from No.13–1 and No.11–2 coal seams are generally low-mineral bituminous coals, which show similar coal rank (Ro,max = 0.71%–0.85%) but vary in maceral and chemical components. In addition, the estimated total gas contents of No.13–1 and No.11–2 coal seams are 9.58–23.59 m3/t and 9.46–13.72 m3/t, respectively. Notably, the growth rate of total gas content exhibits two different stages and shows a logarithmic correlation with reservoir temperature, effective thickness of overlying strata, burial depth and gas pressure. The carbon isotopic value of methane (δ13C1) of No.13–1 coal seam varies from −45.09‰ to −39.23‰ (average, −41.90‰), and that for No.11–2 coal seam ranges from −44.92‰ to −38.45‰ (average, −41.90‰). δ13C1 is unrelated with Ro,max but is positively correlated with burial depth and effective thickness of overlying strata, this indicates that δ13C1 value becomes heavier as burial depth increases, which may be related to the desorption-diffusion-migration effect caused by deeper burial depth and in-situ stress exertion. Moreover, δ13C1 shows a positive linear correlation with total gas content, it is inferred that δ13C1 has a correlation with the control factors of total gas content.

Petrophysics characteristics of coalbed methane reservoir: A comprehensive review

Petrophysics of coals directly affects the development of coalbed methane (CBM). Based on the analysis of the representative academic works at home and abroad, the recent progress on petrophysics characteristics was reviewed from the aspects of the scale-span pore-fracture structure, permeability, reservoir heterogeneity, and its controlling factors. The results showed that the characterization of pore-fracture has gone through three stages: qualitative and semiquantitative evaluation of pore-fracture by various techniques, quantitatively refined characterization of pore-fracture by integrating multiple methods including nuclear magnetic resonance analysis, liquid nitrogen, and mercury intrusion, and advanced quantitative characterization methods of pore-fracture by high-precision experimental instruments (focused-ion beam-scanning electron microscopy, small-angle neutron scattering and computed tomography scanner) and testing methods (µ-CT scanning and X-ray diffraction). The effects of acoustic field can promote the diffusion of CBM and generally increase the permeability of coal reservoirs by more than 10%. For the controlling factors of reservoir petrophysics, tectonic stress is the most crucial factor in determining permeability, while the heterogeneity of CBM reservoirs increases with the enhancement of the tectonic deformation and stress field. The study on lithology heterogeneity of deep and high-dip coal measures, the spatial storage-seepage characteristics with deep CBM reservoirs, and the optimizing production between coal measures should be the leading research directions.

A new approach modeling permeability of mining-disturbed coal based on a conceptual model of equivalent fractured coal

Although many permeability models have been proposed in last few decades to characterize the permeability evolution in poroelastic coalbed methane (CBM) reservoirs, none of the existing model is capable of defining the failure-involved coal permeability behavior which is the common situation for deep coal in-seam boreholes and over matured CBM reservoirs. In this study, a conceptual model named equivalent fractured coal (EFC) was initially proposed to characterize the structure of plastic deformation with new fracture generation. Based on the EFC model, the fracture dilation with deviatoric stress evolution within coal bulk is quantified by an exponential function, and a plastic deformation-based coal permeability (PDP) model was then proposed by incorporating the quantified fracture generation and dilation into a poroelasticity-based permeability model we built previously. Then the PDP model was validated by matching it with the tested permeability data in the unloading-flow experiments. The experiment results show that at the initial stage, the permeability increases slowly with a decrease of the confining pressure, which is mainly caused by the increase of fracture aperture. Later, with the further decrease of the confining pressure, the permeability increases by orders of magnitude, this is dominantly resulted from the generation of large amounts of new cracks. In addition, the results show that the PDP modeled permeability evolution well agreed with the experimental measured results for the whole process of unloading. This suggests that the PDP model cannot only predict the permeability variation under fracture generation and dilation process during plastic deformation, but also can describe that in the case of elastic deformation. The primary implications for this study is to provide a new mechanism-based approach to predict the permeability behavior in deep CBM reservoir during primary depletion or coal seams disturbed by underground coal mining.

Evaluation of gas contents for a multi-seam deep coalbed methane reservoir and their geological controls: In situ direct method versus indirect method

Gas content is one of the most important parameters determining the potential resources and recovery of coalbed methane (CBM). Extensive field work has been conducted for a perspective CBM field in Qinshui Basin with multi-targeted producing coal seams. The gas content was estimated by both direct and indirect methods based on the canister desorption results and methane sorption isotherms. Within the studied CBM field, coal seams are well developed at greater burial depth (>1000 m). The #2, #3, #8, #12, and #15 coal seams in Shanxi and Taiyuan formations are the primary and targeted CBM producing formations. By applying the USBM direct method, the in situ gas contents of the main coal seams are then estimated from the analysis of desorption data. It was found that the indirect method depending on sorption isotherm overestimate the gas content in the studied field because it assumes the gas saturated CBM formation. We found that the coal seams are primarily undersaturated and located under CBM weathered and oxidized zone (CH4 > 90%) with good preservation conditions. The in situ gas contents of the #2, #3, #8, #12, and #15 coals range from 5.62 to 19.36 cm3/g, 11.84 to 31.24 cm3/g, 2.96 to 29.28 cm3/g, 10.96 to 31.19 cm3/g, and 7.91 to 27.32 cm3/g, respectively, with increase trends from the marginal to central areas for all tested seams. Coalification directly determines gas adsorption capacity and it significantly influences the in situ gas content. Coupled contributions of higher gas adsorption capacity and reservoirs pressure lead to higher gas content occur at depth between 1300 and 1550 m. Moreover, high in situ gas content is always associated with roof lithologies with stronger sealing capacity. However, normal faults and groundwater recharge area could promote gas release from the coals. Thus, the internal area of Block II with poor faults development and weak groundwater runoff is a target area for deep CBM preservation.

Supercritical-CO2 Adsorption Quantification and Modeling for a Deep Coalbed Methane Reservoir in the Southern Qinshui Basin, China.

Accurate depiction of the adsorption capacity of supercritical CO2 (ScCO2) by existing adsorption models is an important focus for deep coal seams in CO2-enhanced coalbed methane (CO2-ECBM) recovery. To investigate the applicability of different adsorption models for the adsorption isotherms of ScCO2, the validities of 10 different adsorption models were analyzed, based on analyses of the adsorption characteristics of ScCO2 from deep coal seams of the Southern Qinshui Basin, China. These models include the Langmuir (L) model, two-parameter Langmuir (TL) model, Toth (T) model, Langmuir–Freundlich (LF) model, extended Langmuir (EL) model, double parameter Brunauer–Emmett Teller model, three-parameter BET (TBET) model, Dubinin–Radushkevich (D–R) model, Dubinin–Astakhov (D–A) model, and Ono–Kondo lattice (OK) model. These models were tested for both the excess and absolute adsorption capacities of ScCO2 under various temperatures and pressures. The simulation accuracy of the different adsorption models was analyzed. The optimal models for the adsorption of ScCO2 in deep coal seams were selected based on a comprehensive analysis of the simulation parameters, standard error, and residual sum of squares. There were obvious differences in the validity of the different adsorption models in terms of the excess adsorption capacity and absolute adsorption capacity of ScCO2. The D–A and D–R models are the optimal adsorption models for the adsorption isotherms of the excess adsorption of ScCO2 for the whole tested pressure range. The T, TL, and D–R models are the optimal adsorption models in simulation of the excess adsorption capacity of ScCO2 for the selected adsorption models when the equilibrium pressure is divided into two sections at the point of 8.13 MPa. In simulation of the absolute adsorption capacity of ScCO2, the TBET and LF models are the optimal adsorption models among the selected models when the equilibrium pressure is less than or equal to 8.13 MPa. The linear, exponential, logarithmic, power function, and polynomial adsorption simulation all have good precision in the simulation of the absolute adsorption capacity of ScCO2 when the pressure is beyond 8.13 MPa.

Reservoir reconstruction technologies for coalbed methane recovery in deep and multiple seams

Multiple coal seams widely develop in the deep Chinese coal-bearing strata. Ground in situ stress and coal seam gas pressure increase continuously with the increase of the mining depth, and coal and gas outburst disasters become increasingly severe. When the coal is very deep, the gas content and pressure will elevate and thus coal seams tends to outburst-prone seams. The safety and economics of exploited first-mined coal seams are tremendously restricted. Meanwhile, the multiple seams occurrence conditions resulted in different methane pressure systems in the coal-bearing strata, which made the reservoir reconstruction of coal difficult. Given the characteristics of low saturation, low permeability, strong anisotropy and soft coal of Chinese coal seams, a single hydraulic fracturing surface well for reservoir reconstruction to pre-drain the coalbed methane (CBM) of multiple seams concurrently under the different gas pressure systems has not yet gained any breakthroughs. Based on analyses of the main features of deep CBM reservoirs in China, current gas control methods and the existing challenges in deep and multiple seams, we proposed a new technology for deep CBM reservoir reconstruction to realize simultaneous high-efficiency coal mining and gas extraction. In particular, we determined the first-mined seam according to the principles of effectiveness and economics, and used hydraulic fracturing surface well to reconstruct the first-mined seam which enlarges the selection range of the first-mined seam. During the process of mining first-mined seam, adjacent coal seams could be reconstructed under the mining effect which promoted high-efficiency pressure relief gas extraction by using spatial and comprehensive gas drainage methods (combination of underground and ground CBM extraction methods). A typical integrated reservoir reconstruction technology, “One well for triple use”, was detailed introduced and successfully applied in the Luling coal mine. The application showed that the proposed technology could effectively promote coal mining safety and simultaneously high-efficiency gas extraction.

Evaluation of geological features for deep coalbed methane reservoirs in the Dacheng Salient, Jizhong Depression, China

The Dacheng Salient of the northeast Jizhong Depression is one of the most promising areas for deep coalbed methane (CBM) development in China. This work investigates the Permo-Carboniferous (C-P) Taiyuan and Shanxi Formation coals and CBM geology and gas accumulation characteristics in the Dacheng Salient based on field data from 24 wells and laboratory measurements of eight coal samples and eight mudstone and sandstones from exploration well D1-1.The results show that the coal rank in the Dacheng Salient is a high-volatile C bituminous coal to low-volatile bituminous coal (0.54–1.85% Ro) controlled by the magmatism in the region. The coals vary from 2.94 to 8.58% in porosity and 0.263m2/g to 2.6m2/g in BET surface area. The in-situ permeability is low, normally less than 0.5×10−3μm2.Methane isothermal adsorption measurements of five coal samples reveal that their maximum adsorption capacity (on an as-received basis) varies from 17.13 to 25.98m3/t, with an apparent relationship with ash yield. The roof and floor of coal seams are mainly mudstone, with minor quantities of sandy mudstone and carbonate; all have the ability to be suitable cap rocks with adequate sealing capacity and large breakthrough pressure. The in-place gas content range from 10.23 to 1.41m3/t with a decreasing trend from No. 3 to No. 6 coal seam group in the D1-1 well due to effects by the active ground water near the east Jinghai-Dacheng fault. However, the gas content and the gas saturation increase with burial depth and ground water salinity, and decrease with coal rank. Finally, based on a comprehensive analysis of coal thickness, gas content, hydrogeology conditions, roof, floor, and depth properties, this study reveals that the best prospective target areas for CBM production are the south-central parts of the Dacheng Salient at1200~1600m in depth