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Collaborating Authors
Results
Water Distribution Characteristic and Effect on Methane Adsorption Capacity in Shale Clays
Li, Jing (China University Of Petroleum Beijing) | Wu, Keliu (University of Calgary) | Shi, Juntai (China University Of Petroleum Beijing) | Li, Xiangfang (China University Of Petroleum Beijing) | Li, Yingying (CNOOC Research Institute Beijing) | Feng, Dong (China University Of Petroleum Beijing) | Zhang, Tao (China University Of Petroleum Beijing) | Xu, Min (China University Of Petroleum Beijing) | Bai, Yangai (China University Of Petroleum Beijing)
Abstract Methane adsorption in shale is result of gas-liquid-solid interaction rather than gas-solid interaction by considering the initial water saturation in actual condition. As an important constituent of inorganic matter, clay minerals can provide additional adsorption capacity due to high internal surface area. Under dry conditions, both inorganic and organic materials dominate methane adsorption content. However, under reservoir conditions, water always adsorb on clay particle surface, which will significantly reduce the adsorption capacity of methane. Thus, the experimental evaluation of adsorbed gas reserves with dry samples or other improper conditions will misestimate the total gas in place (OGIP). What's more, the commonly used Langmuir equation is not available in describing the complex gas-water competitive adsorption under different moisture conditions. Thus, the mechanism and mathematical model to describe gas-water-clay three phase interactions is badly needed. In this paper, we analyze the interaction characteristics between methane, water film and clay base on adsorption theory, and results reveal that: methane adsorption on clay (dry) is a typical gas-soild interaction; however, methane adsorption on clay bound water film should belong to gas-liquid interaction. Based on our analysis, a united model is established to describe gas-water-clay interactions, in which, (i) gas-solid interface Langmuir equation is employed to describe methane adsorption on clay (dry); (ii) gas-liquid interface Gibbs equation, instead of Langmuir equation, is employed to describe methane adsorption on water film; (iii) water coverage coefficient was defined to describe the transition between gas-solid adsorption and gas-liquid adsorption; (iv) Langmuir equation and Gibbs equation integrated by water coverage coefficient is established to describe gas-liquid-solid interaction. Meanwhile, mathematical model is presented to quantify water films thickness bound on clay based on DLVO theory (by considering disjoining pressure in nanoscale water film). The preliminary result shows that, the water saturation in shale clay pore mainly depends on relative humidity and pore size. Under a certain shale humidity system, water saturation is significant effected by pore size. And the pore size is smaller, the water saturation is higher. Otherwise, a capillary condensation phenomenon is also found in our work. Thus, the water saturaion distribute in different pores mainly as: (i) capillary water in the small pores; (ii) water film in the lager pores. Furthermore, considering the water distribution characteristic, the effect of moisture on methane adsorption capacity in shale clay is mainly for two aspects: (i) small pores blocked by water are invalid for methane adsorption, (ii) large pores bounded by water film change interaction characteristics for methane adsorption (from gas-solid interaction to the gas-liquid interaction). And the overall effect could reduce the adsorption capacity by 90% in our study. The comparison presents the same trend between calculation results by our united model describing gas-water-clay interactions, and experimental result of methane adsorption on clay-rich shale under different mositure conditions by Chalmers (2012). Thus, our model is reasonable and available to describe water and methane competitive adsorption in shale inorganic mineral or clay-rich shale. Furthermore, our model can be applied to predict methane absorption capacity under different water saturation condition in shale system with a real pore size distribution. Our present work reveals mechanism of moisture effect on the methane absorption capacity and lays foundations of evaluating the GIP in shale system more accurately.
- North America (0.93)
- Asia > China (0.47)
- Oceania > Australia (0.46)
- Research Report > Experimental Study (0.66)
- Research Report > New Finding (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Oceania > Australia > South Australia > Cooper Basin > Roseneath Formation (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (0.68)
Mechanism of Liquid-Phase Adsorption and Desorption in Coalbed Methane Systems - A New Insight into an Old Problem
Li, Jing (China University Of Petroleum Beijing) | Li, Xiangfang (China University Of Petroleum Beijing) | Li, Yingying (CNOOC Research Institute Beijing) | Shi, Juntai (China University Of Petroleum Beijing) | Wu, Keliu (University of Calgary) | Dong, Feng (China University Of Petroleum Beijing) | Li, Yanzun (China University Of Petroleum Beijing) | Yang, Jian (China University Of Petroleum Beijing) | Bai, Yangai (China University Of Petroleum Beijing)
Abstract Coalbed methane (CBM) recovery is a process of desorption rather than adsorption. Traditional experimental studies of methane adsorption/desorption on moist coal samples illustrate that, there is little hysteresis between adsorption and desorption processes, and these two behavior could be described by Langmuir equation. However, it is widely believed that coal porosity is normally occupied by water, and few researches focus on the gas sorption mechanism in condition of pore systems saturated with water. In this condition, there is an equilibrium between methane molecular dissolution into pore water and adsorption on (or desorption from) pore surface. And it is a typical liquid-solid internal interaction rather than gas-solid internal interaction. This paper presents experiments with methane adsorption/desorption on coal samples saturated with water and illustrates the significant difference between liquid-solid adsorption and gas-solid adsorption. In this work, we carry out three sets of experiments with coal samples immersed in water, and the equilibrium pressure is P=5.445 MPa, 5.220 MPa and 2.965 MPa respectively. Subsequently, we conduct desorption experiments based on the former adsorption experiments to simulate the production process in aqueous environment with decreasing pressure. During desorption process, we are surprised to find that desorption amount changes slightly with different pressure drops, and desorption ratio for four sets of experiments is only 3.36%, 4.98% and 4.21% respectively. This dramatic results indicate that the desorption amount from saturated aqueous solution is not sensitive to pressure, which differs considerably from gas-phase desorption case. Furthermore, we analyze the Gibbs free energy change during adsorption/desortion processes in these two different systems: gas-solid and liquid-solid interface systems. It should be noted that, in an ideal gas-solid interface system (such as adsorption/desortion on flat surface case without the effect of pore structure), the Gibbs free energy change in adsorption are approximately equal to that in desortion processes, thus, the phase transition between absorbed layer and bulk is quasi-reversible, and no hysteresis exist in these two processes. However, in the liquid-solid interface system, due to the additional energy consumed by nucleation, it requires more energy for unit molar of methane during desorption process than adsorption process, which indictes that adsoption/desorption of liquid-solid interface are unreversible. Based on this theory, we established a hysteretic model to describe the hysteresis phenomenon during adsoption/desorption from aqueous environment, and this model can be perfectly verified by our experiment results. Our result demonstrates that the process of the methane desorption from micropores under water saturated condition is hysteretic seriously. This meaningful finding indicates that when almost no free gas exists in matrix pores, i.e., only absorbed gas and dissolved gas exist, and adsorbed gas almost cannot desorb and gas production of CBM wells will be very low. In other words, the larger amount of adsorbed gas doesn't always yield the larger gas productivity, and free gas in matrix pores could induce adsorbed gas to desorb.
- North America > Canada (0.46)
- Asia > China (0.29)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.68)
- Geology > Geological Subdiscipline (0.67)
New Models of Brittleness Index for Shale Gas Reservoirs: Weights of Brittle Minerals and Rock Mechanics Parameters
Hu, Yuan (University of Calgary) | Gonzalez Perdomo, M. E. (University of Adelaide) | Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary) | Zhang, Kai (University of Calgary) | Yi, Jie (University of Queensland) | Ren, Guoxian (University of Calgary) | Yu, Yanguo (University of Calgary)
Abstract Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they ignore the weights of these two factors. Also, it is imprecise to calculate BI by considering quartz (or dolomite) as the only brittle mineral in mineralogy-based BI prediction. Shale gas reservoirs like Eagle Ford are rich in carbonate minerals. If the carbonate minerals are ignored in those reservoirs, the value of BI will be greatly underestimated. On the other hand, brittle minerals like quartz, dolomite and calcite play different roles in BI calculation. If we equally treat them without weighting in BI prediction, the BI being calculated will be inaccurate as well. This paper analyzes the influence of calcite on rock mechanics parameters and BI comparing with quartz and clay. Then new models of BI prediction are built to characterize the weight of each brittle mineral and rock mechanics parameter. Based on the least squares method, optimal values of weight coefficients will be obtained by iteration. The results show that calcite improves rock brittleness and should be considered as a brittle mineral in BI prediction. However, the weight of calcite is less than quartz. From the statistics results, quartz > dolomite > calcite > clay occurs in improving BI. The results also show that Young's modulus plays a more important role in BI prediction than Poisson's ratio.
- Overview > Innovation (0.63)
- Research Report > New Finding (0.49)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.91)
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.48)
A Novel Model of Brittleness Index for Shale Gas Reservoirs: Confining Pressure Effect
Hu, Yuan (University of Calgary) | Perdomo, M. E. (University of Adelaide) | Wu, Keliu (University of Calgary) | Chen, Zhangxin (University of Calgary) | Zhang, Kai (University of Calgary) | Ji, Dongqi (University of Calgary) | Zhong, He (University of Calgary)
Abstract Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they both ignore the effect of confining pressure. Shale is usually distributed at different depth under different confining pressure. Models without considering the influence of confining pressure will directly lead to inaccuracy in BI calculation, thus resulting in the failure of hydraulic fracturing. In this work, we compared confining pressure with rock mechanics parameters and the microcrack quantity of a core, introduced "fracture toughness" to explain how confining pressure influences BI, and finally developed a new model to correct the effect of confining pressure in BI calculation. Fracture toughness is an important parameter that characterizing a rock’s resistance to a fracture. It increases with confining pressure, since an increase of confining pressure may close preexisting cracks and restrict the crack propagation. The results show that BI is usually larger at low confining pressure than at high pressure. Also, higher content in brittle mineral does not necessarily mean brittler. The results calculated by the new model, which considers the influence of Young’s modulus, Poisson’s ratio, tensile strength, confining pressure and fracture toughness in BI calculation, match well with experimental results.
- North America > United States > Texas (0.48)
- Asia (0.47)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.49)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- Geophysics > Seismic Surveying (0.68)
- Geophysics > Borehole Geophysics (0.49)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)