In this paper,marine shale cores taken from Zhaotong,Changning and Weiyuan Blocks in South China were used as samples to investigate the interaction between fracturing fluids and shale and the retention mechanisms.Fir...In this paper,marine shale cores taken from Zhaotong,Changning and Weiyuan Blocks in South China were used as samples to investigate the interaction between fracturing fluids and shale and the retention mechanisms.Firstly,adsorption,swelling,dissolution pore,dissolution fluid mineralization degree and ionic composition were experimentally studied to reveal the occurrence of water in shale and the reason for a high mineralization degree.Then,the mechanisms of water retention and mineralization degree increase were simulated and calculated.The scanning electron microscopy(SEM)analysis shows that there are a large number of micro fractures originated from clay minerals in the shale.Mineral dissolution rates of shale immersed in ultrasonic is around 0.5-0.7%.The ionic composition is in accordance with that of formation water.The clay minerals in core samples are mainly composed of chlorites and illites with a small amount of illites/smectites,but no montmorillonites(SS),and its content is between 18%and 20%.It is verified by XRD and infrared spectroscopy that the fracturing fluid doesn't flow into the space between clay mineral layers,so it can't lead to shale swelling.Thus,the retention of fracturing fluids is mainly caused by the adsorption at the surface of the newly fractured micro fractures in shale in a mode of successive permeation,and its adsorptive saturation rates is proportional to the pore diameters.It is concluded that the step-by-step extraction of fracturing fluids to shale and the repulsion of nano-cracks to ion are the main reasons for the abrupt increase of mineralization degree in the late stage of flowing back.In addition,the liquid carrying effect of methane during the formation of a gas reservoir is also a possible reason.Based on the experimental and field data,fracturing fluid flowback rates and gas production rates of 9 wells were analyzed.It is indicated that the same block follows an overall trend,namely,the lower the flowback rates,the more developed the micro fractures,the better the volume simulation effect and the higher the gas production rates.展开更多
In this paper, the methods developed by?[1] are used to analyze flowback data, which involves modeling flow both before and after the breakthrough of formation fluids. Despite the versatility of these techniques, achi...In this paper, the methods developed by?[1] are used to analyze flowback data, which involves modeling flow both before and after the breakthrough of formation fluids. Despite the versatility of these techniques, achieving an optimal combination of parameters is often difficult with a single deterministic analysis. Because of the uncertainty in key model parameters, this problem is an ideal candidate for uncertainty quantification and advanced assisted history-matching techniques, including Monte Carlo (MC) simulation and genetic algorithms (GAs) amongst others. MC simulation, for example, can be used for both the purpose of assisted history-matching and uncertainty quantification of key fracture parameters. In this work, several techniques are tested including both single-objective (SO) and multi-objective (MO) algorithms for history-matching and uncertainty quantification, using a light tight oil (LTO) field case. The results of this analysis suggest that many different algorithms can be used to achieve similar optimization results, making these viable methods for developing an optimal set of key uncertain fracture parameters. An indication of uncertainty can also be achieved, which assists in understanding the range of parameters which can be used to successfully match the flowback data.展开更多
A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the inte...A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the interlayer stress difference,the fracturing discharge rate and the fracturing fluid viscosity.The results show that these factors affect the gas and water production by influencing the fracture size.The interlayer stress difference can effectively control the fracture height.The greater the stress difference,the smaller the dimensionless reconstruction volume of the reservoir,while the flowback rate and gas production are lower.A large displacement fracturing construction increases the fracture-forming efficiency and expands the fracture size.The larger the displacement of fracturing construction,the larger the dimensionless reconstruction volume of the reservoir,and the higher the fracture-forming efficiency of fracturing fluid,the flowback rate,and the gas production.Low viscosity fracturing fluid is suitable for long fractures,while high viscosity fracturing fluid is suitable for wide fractures.With an increase in the fracturing fluid viscosity,the dimensionless reconstruction volume and flowback rate of the reservoir display a non-monotonic behavior,however,their changes are relatively small.展开更多
基金Project supported by National Key Basic Research Program of China(937 program)“Basic research of high-efficiency marine shale gas development in South China”(No.2013CB228000).
文摘In this paper,marine shale cores taken from Zhaotong,Changning and Weiyuan Blocks in South China were used as samples to investigate the interaction between fracturing fluids and shale and the retention mechanisms.Firstly,adsorption,swelling,dissolution pore,dissolution fluid mineralization degree and ionic composition were experimentally studied to reveal the occurrence of water in shale and the reason for a high mineralization degree.Then,the mechanisms of water retention and mineralization degree increase were simulated and calculated.The scanning electron microscopy(SEM)analysis shows that there are a large number of micro fractures originated from clay minerals in the shale.Mineral dissolution rates of shale immersed in ultrasonic is around 0.5-0.7%.The ionic composition is in accordance with that of formation water.The clay minerals in core samples are mainly composed of chlorites and illites with a small amount of illites/smectites,but no montmorillonites(SS),and its content is between 18%and 20%.It is verified by XRD and infrared spectroscopy that the fracturing fluid doesn't flow into the space between clay mineral layers,so it can't lead to shale swelling.Thus,the retention of fracturing fluids is mainly caused by the adsorption at the surface of the newly fractured micro fractures in shale in a mode of successive permeation,and its adsorptive saturation rates is proportional to the pore diameters.It is concluded that the step-by-step extraction of fracturing fluids to shale and the repulsion of nano-cracks to ion are the main reasons for the abrupt increase of mineralization degree in the late stage of flowing back.In addition,the liquid carrying effect of methane during the formation of a gas reservoir is also a possible reason.Based on the experimental and field data,fracturing fluid flowback rates and gas production rates of 9 wells were analyzed.It is indicated that the same block follows an overall trend,namely,the lower the flowback rates,the more developed the micro fractures,the better the volume simulation effect and the higher the gas production rates.
文摘In this paper, the methods developed by?[1] are used to analyze flowback data, which involves modeling flow both before and after the breakthrough of formation fluids. Despite the versatility of these techniques, achieving an optimal combination of parameters is often difficult with a single deterministic analysis. Because of the uncertainty in key model parameters, this problem is an ideal candidate for uncertainty quantification and advanced assisted history-matching techniques, including Monte Carlo (MC) simulation and genetic algorithms (GAs) amongst others. MC simulation, for example, can be used for both the purpose of assisted history-matching and uncertainty quantification of key fracture parameters. In this work, several techniques are tested including both single-objective (SO) and multi-objective (MO) algorithms for history-matching and uncertainty quantification, using a light tight oil (LTO) field case. The results of this analysis suggest that many different algorithms can be used to achieve similar optimization results, making these viable methods for developing an optimal set of key uncertain fracture parameters. An indication of uncertainty can also be achieved, which assists in understanding the range of parameters which can be used to successfully match the flowback data.
文摘A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the interlayer stress difference,the fracturing discharge rate and the fracturing fluid viscosity.The results show that these factors affect the gas and water production by influencing the fracture size.The interlayer stress difference can effectively control the fracture height.The greater the stress difference,the smaller the dimensionless reconstruction volume of the reservoir,while the flowback rate and gas production are lower.A large displacement fracturing construction increases the fracture-forming efficiency and expands the fracture size.The larger the displacement of fracturing construction,the larger the dimensionless reconstruction volume of the reservoir,and the higher the fracture-forming efficiency of fracturing fluid,the flowback rate,and the gas production.Low viscosity fracturing fluid is suitable for long fractures,while high viscosity fracturing fluid is suitable for wide fractures.With an increase in the fracturing fluid viscosity,the dimensionless reconstruction volume and flowback rate of the reservoir display a non-monotonic behavior,however,their changes are relatively small.
