Yidong Cai

Effects of pressure and temperature on gas diffusion and flow for primary and enhanced coalbed methane recovery

Due to the rapid increase of coalbed methane (CBM) exploration and development activities in China, gas adsorption and flow behavior for Chinese coals are of great interest for the industry and research community. How pressure and temperature affect the gas adsorption and flow on different rank coals are not only important for CBM recovery but also important for CO2 or N2 enhanced CBM recovery, since gases are often injected at a temperature different to the reservoir temperature. In this work, gas adsorption and permeability of three different rank Chinese coals are measured using CH4, N2 and CO2 at three temperatures, 20°C, 35°C and 50°C. Gas diffusivity and permeability with respect to gas species, pore pressure, effective stress and temperature are studied. The three coals are SQB-1 from Southern Qinshui Basin, JB-1 from Junggar Basin and OB-1 from Ordos Basin. Gas adsorption results show that both pressure and temperature have significant impact on adsorption behavior for SQB-1 and JB-1 using CH4. For higher rank coal SQB-1, adsorption isotherm tends to reach adsorption capacity quicker with respect to pressure. However, the maximum adsorption capacity is higher for the lower rank coal JB-1. Moreover, temperature has a stronger effect on reducing adsorption capacity for lower rank coal. Gas diffusivity results for OB-1 and JB-1 show that CO2 diffusivity is generally higher than that of CH4 and then N2. This could be related with their different kinetic diameters and their interaction with the coal. Both pressure and temperature have impact on gas diffusivity. In general, gas diffusivities increase with pressure and temperature. Permeability results show that it varies greatly with respect to coal rank with highest rank coal having the lowest permeability. Permeability is also strongly sensitive to effective stress and pore pressure. Temperature has a noticeable impact on permeability change. Permeability changes differently with temperature increase for the different rank coal samples studied. This may be attributed to the combined effect of coal strain change due to gas adsorption and thermal expansion. These results have significant implications for the design of enhanced CBM recovery and CO2 storage for different rank coals as injecting gas at different temperature and pressure would affect the CO2 injectivity and the CBM production rate.

Physical characterization of the pore-fracture system in coals, Northeastern China

Usually mercury intrusion/extrusion curves reflect the characteristics of open pore-fracture system of coals. Using this method, the nature of the open pore-fractures of 18 Chinese coals (varying in vitrinite reflectance from 0.65 to 1.76%Ro, max) was studied. A quantitative evaluation method for micropore (0-0.1 μm, in diameter), mesopore (0.1-1 μm), macropore (1-10 μm) and fracture (>10 μm) within coals was established by the mercury intrusion curves. The method was verified by the fractal geometry theory. Moreover, three Types (I, II and III) of the open pore-fracture systems of coals were analyzed by combining mercury withdrawal efficiency and permeability with pore size distribution. Results show that (a) Type I coals are characterized by abundant open micropores (mean 62.8 vol. %) and rarely open fractures, which leads to a large minable potential but very low production rate for coalbed methane (CBM); (b) Type II coals have low minable potential and high production rate for CBM, mainly because of the distribution of a few micropores (mean 35.5 vol. %) and a large number fractures (mean 19.7 vol. %) in coals; (c) Type III coals are the most appropriate to exploit CBM due to the existence of optimal open pore-fracture system (micropores, mean 58.5 vol. %; fractures, mean 15.4 vol. %) within coals.

Pore structure and compressibility of coal matrix with elevated temperatures by mercury intrusion porosimetry

To gain a better understanding of the effect of heat (e.g., magma intrusion, geothermal fluids and enhanced coal-bed methane recovery process) on coal reservoir properties, the pore structure and compressibility of coal matrix for low rank coal (0.69% Ro, m) with elevated temperatures were investigated by using multiple methods, including thermogravimetry-mass spectrometry (TG-MS), scanning electron microscope (SEM), N2 adsorption/desorption at 77 K and mercury intrusion porosimetry (MIP). The results from TG-MS showed that moisture and partial volatiles were removed from the coal matrix, and pore structure almost remained unchanged during the low heat treatment (25∼200°C). The micropores and transition pores consisted of more than 80% of the total pore volume based on the MIP. The pore structure was slightly changed following the temperature increase to 400°C, and the bound moisture and partial organics in the coal were released and decomposed by the increased heat, respectively. When temperature reached 400°C, organic matter decomposition of the coal released a large amount of hydrocarbon and micromolecule gases. The meso- and macropore in the coal were significantly developed, occupying ∼35% of the total pore volume. Although there was no large change in generated gas composition after 600°C, the pore volume and structures, including pore size distribution, pore volume and pore connectivity, were significantly changed based on the MIP. The pore structure acquired from MIP exhibited a deviation when the mercury intruded pressure reached 10 MPa. A fractal model was introduced to correct the MIP data and acquire the pore compressibility of the coal matrix. The results showed that the pore compressibility decreased with increasing pressure and temperature. Thus, this study provides significant implications of the pore structure evolution of underground coals that encounter heating.

COMPARISON OF PORE FRACTAL CHARACTERISTICS BETWEEN MARINE AND CONTINENTAL SHALES

Fractal characterization offers a quantitative evaluation on the heterogeneity of pore structure which greatly affects gas adsorption and transportation in shales. To compare the fractal characteri...

Fracture permeability evaluation of a coal reservoir using geophysical logging: A case study in the Zhengzhuang area, southern Qinshui Basin:

To evaluate the heterogeneity of the No. 3 coal reservoir fracture permeability of Zhengzhuang area in the southern Qinshui Basin, several fracture models were reviewed and their applicability to coal reservoirs was discussed. Fourteen coalbed methane exploration wells with well test data were used to perform an optimization of the fracture parameter models. The results showed that fracture porosity presents a strong correlation with the well test permeability. Fracture porosity was calculated by the dual laterolog iterative method, in which the fracture distortion coefficient Kr was introduced. Based on this correlation, the F-S fracture permeability calculation model was adopted to acquire the fracture permeability of coalbed methane wells in the Zhengzhuang area. The predicted fracture permeability is generally low in the Zhengzhuang area, ranging from 0.01 to 0.37 mD, with an average of 0.07 mD. The planar permeability is strongly heterogeneous. The permeability of the No. 3 coal reservoir is relatively low close to the Shitou and Houchengyao normal faults in the southern Zhengzhuang area, but high in the midwestern Zhengzhuang area, with an average of 0.21 mD. The fracture permeability of the coal reservoir in the vertical direction is in the range of 0.005 to 0.680 mD, decreasing significantly with increasing burial depth. The regional distribution of permeability is mainly controlled by burial depth and in situ stresses. The permeability is high in the shallow area and in the minor concomitant fault zone, but low in the folding area and near major faults. The heterogeneity of the coal reservoir has an important effect on the permeability in the vertical direction. The best prospective target area for coalbed methane production is predicted by the minimum requirements of gas content and thus permeability in this area. The prediction result has a good corresponding relation with the current production capacity of coalbed methane wells.

Geological factors on gas entrapment mechanism and prediction of coalbed methane of the no. 6 coal seam in the Jungar coalfield, northeast Ordos Basin, China

Low rank coal reservoirs of the no. 6 coal seam in the Jungar coalfield are characterised by low gas content but favourable porosity and permeability for recovery. The accumulation and enrichment of CBM is favoured by the presence of multiple (five seams) and thick (12.7–40.4 m) seams, adequate permeability (3.6–26 mD) and significant abundance of coal resource (5.44 × 10 10 tonnes), but hindered by low observed gas content (0.01–1.5 m 3 /t), which is shown to result from both shallow burial depth and high permeability of the seams. However, the sheer magnitude of the no. 6 coal resource offsets this shortcoming of low gas content and makes this a good prospect for exploration and exploitation. Conditions are most favourable in the southwest coalfield where a monoclinal structure and favourable hydrodynamic conditions have prevented gas escape. Areas of the no. 6 coal seam buried under the CH 4 weathering line ( > 860 m), with larger coal thickness ( > 10 m), and higher gas content ( > 1.2 m 3 /t) have the greatest potential for CBM enrichment.

A new fracture permeability model of CBM reservoir with high-dip angle in the southern Junggar Basin, NW China

Predicting the permeability of coalbed methane (CBM) reservoirs is significant for coalbed methane exploration and coalbed methane development. In this work, a new fracture permeability model of coalbed methane reservoir with high-dip angle in the southern Junggar Basin, NW China is established based on the Poiseuille and Darcy laws. The fracture porosity in coalbed methane reservoir is calculated by applying 3D finite element method. The formation cementing index m was calculated by combining fractal theory and the data of acoustic logging, compensated neutron logging, and density logging with the space method. Based on Poiseuille and Darcy laws, the curvature τ is introduced to derive this new method for obtaining the permeability of the original fractures in coalbed methane reservoirs. Moreover, this newly established permeability model is compared with the permeability from the well testing, which shows a very good correlation between them. This model comprehensively includes the effects of fracture porosity, reservoir pore structure, and development conditions on fracture permeability. Finally, the permeability prediction of coalbed methane reservoir with high-dip angle in the southern Junggar Basin, NW China is conducted, which correlates very well with the well test permeability (R2 = 0.83). Therefore, this model can be used to accurately predict the coalbed methane reservoir permeability of low rank coals in the southern Junggar Basin. The permeability of the No.43 coalbed methane reservoir for the coalbed methane wells without well testing data is evaluated, which ranges from 0.000251 to 0.379632 mD. This significant change in permeability may indicate a complex coalbed methane reservoir structure in the southern Junggar Basin, NW China.

Pore Structure Characteristics of Shale Gas Reservoir of Yingcheng Formation in Lishu Depression, Songliao Basin

organic-rich shale from Lishu Depression (LSD) of the southern Songliao Basin located in northeast China has significant shale gas potential by geochemistry and petrology. The organic-rich shale contains kerogen type II and III, and has a total organic carbon (TOC) content of 1.5 wt. %. The random vitrinite reflectance (Ro, m >2.0%) is in the high thermal evolution stage, which is prone to shale gas generation, but few have researched the shale reservoir characterization in LSD. Multiple methods, including optical microscope, scanning electron microscope and energy dispersive spectrum analysis (SEM-EDS), nitrogen adsorption/desorption analysis and X-ray diffraction (XRD) were conducted to determine the shale reservoirs characteristics of pore size/ volume distribution and their affecting factors. The LSD shale reservoirs develop a variety of etiogenic pore types, including mineral matrix pores (intergranular pore and intragranular pore), matrix pores and fracture-pores. The charred sporangium pores, air holes, charcoal pore group, higher plant debris pores, celestitemicrolite pores are well developed. The LSD shale occurs a large number of nanoscale pores, which mostly found in the dispersed particles of organic matter, but also found a few nanoscale pores between the parallel bedding in organic-rich shale. Nanometer pore shapes present the oval, a swirl shape edge, multifaceted angle pores or grape-like micellar structure. N2 adsorption/desorption analysis shows that the pore structures are mainly the ink bottle pore, wedge shaped pore and tablet slit pore. The absorbed pore (<100 nm) accounted for 85% of BJH pore volume and 87% of BET specific surface area ,which are the main contributor for the Yingchang Formation shale. The mineral analysis results show a significant percentage of brittle minerals (32%~63%) and clay minerals dominated by illite and montmorillonite. Morphology of minerals is crystal gypsum, granular barite and quartz vein. The shale TOC content, minerals constitute and content influence the development of shale pores. Overall, shale BJH pore volume increases with increasing TOC content, clay mineral, especially the montmorillonite and illite contents has significant effects on shale gas content and organic matter maturity is negatively related to the LSD shale porosity. ZHOU Sandong, LIU Dameng, CAI Yidong and TANG Jigaung, 2015. Pore Structure Characteristics of Shale Gas Reservoir of Yingcheng Formation in Lishu Depression, Songliao Basin. Acta Geologica Sinica (English Edition), 89(supp.): 142.