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
After hydraulic fracturing treatment,a reduction in permeability caused by the invasion of fracturing fluids is an inevitable problem,which is called water blocking damage.Therefore,it is important to mitigate and eli...After hydraulic fracturing treatment,a reduction in permeability caused by the invasion of fracturing fluids is an inevitable problem,which is called water blocking damage.Therefore,it is important to mitigate and eliminate water blocking damage to improve the flow capacities of formation fluids and flowback rates of the fracturing fluid.However,the steady-state core flow method cannot quickly and accurately evaluate the effects of chemical agents in enhancing the fluid flow capacities in tight reservoirs.This paper introduces a time-saving and accurate method,pressure transmission test(PTT),which can quickly and quantitatively evaluate the liquid flow capacities and gas-drive flowback rates of a new nanoemulsion.Furthermore,scanning electron microscopy(SEM)was used to analyze the damage mechanism of different fluids and the adsorption of chemical agents on the rock surface.Parallel core flow experiments were used to evaluate the effects of the nanoemulsion on enhancing flowback rates in heterogeneous tight reservoirs.Experimental results show that the water blocking damage mechanisms differ in matrices and fractures.The main channels for gas channeling are fractures in cracked cores and pores in non-cracked cores.Cracked cores suffer less damage from water blocking than non-cracked cores,but have a lower potential to reduce water saturation.The PTT and SEM results show that the permeability reduction in tight sandstones caused by invasion of external fluids can be list as guar gum fracturing fluid>slickwater>brine.Parallel core flow experiments show that for low-permeability heterogenous s andstone reservoirs with a certain permeability ratio,the nanoemulsion can not only reduce reverse gas channeling degree,but also increase the flowback rate of the fracturing fluid.The nanoemulsion system provides a new solution to mitigate and eliminate water blocking damage caused by fracturing fluids in tight sandstone gas reservoirs.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.
基金financially supported by the National Science Foundation of China(Grant No.51804033)China Postdoctoral Science and Foundation(Grant No.2018M641254)the National Science and Technology Major Projects of China(Grant Nos.2016ZX05051,2016ZX05014-005,and 2017ZX05030)。
文摘After hydraulic fracturing treatment,a reduction in permeability caused by the invasion of fracturing fluids is an inevitable problem,which is called water blocking damage.Therefore,it is important to mitigate and eliminate water blocking damage to improve the flow capacities of formation fluids and flowback rates of the fracturing fluid.However,the steady-state core flow method cannot quickly and accurately evaluate the effects of chemical agents in enhancing the fluid flow capacities in tight reservoirs.This paper introduces a time-saving and accurate method,pressure transmission test(PTT),which can quickly and quantitatively evaluate the liquid flow capacities and gas-drive flowback rates of a new nanoemulsion.Furthermore,scanning electron microscopy(SEM)was used to analyze the damage mechanism of different fluids and the adsorption of chemical agents on the rock surface.Parallel core flow experiments were used to evaluate the effects of the nanoemulsion on enhancing flowback rates in heterogeneous tight reservoirs.Experimental results show that the water blocking damage mechanisms differ in matrices and fractures.The main channels for gas channeling are fractures in cracked cores and pores in non-cracked cores.Cracked cores suffer less damage from water blocking than non-cracked cores,but have a lower potential to reduce water saturation.The PTT and SEM results show that the permeability reduction in tight sandstones caused by invasion of external fluids can be list as guar gum fracturing fluid>slickwater>brine.Parallel core flow experiments show that for low-permeability heterogenous s andstone reservoirs with a certain permeability ratio,the nanoemulsion can not only reduce reverse gas channeling degree,but also increase the flowback rate of the fracturing fluid.The nanoemulsion system provides a new solution to mitigate and eliminate water blocking damage caused by fracturing fluids in tight sandstone gas reservoirs.
