Numerical Simulation Of Time Dependent Wellbore Instability In Shale Formation And Application

In recent years,the global energy supply and demand crisis has been ever intensifying.Shale gas and tight oil,which are the new important oil and gas reservoirs,have drawn increasing attention.In order to effectively develop unconventional reservoirs,the long horizontal drilling in shale formations is adopted,which is prone to cause wellbore instability and results in seriously restricting the progress and quality of drilling.Therefore,it is necessary to study the time dependent wellbore instability in shale formation and optimize the density and system of the drilling fluid,which can determine the collapse cycle of shale formations and prevent wellbore instability.Taking the drilling in shale formations as the engineering background,this study combines the methods of theoretical analysis and numerical simulation,and establishes the non-isothermal fluid-solid coupling mathematical model of the time dependent wellbore instability in shale formations using the theory of rock mechanics,percolation flow mechanics,thermodynamics and physical chemistry.In the time dependent wellbore instability model,the strength weakening of shale is considered.Then the numerical solution of the mathematical model is obtained.This thesis systematically studies the immanent mechanism of the time dependent wellbore instability in shale formations.Efforts are made to establish the integral theoretical system of the multi-field coupling numerical simulation study of time-dependent wellbore instability for shale formations,and provide the scientific basis for the optimization design and safe drilling in shale formation.Firstly,based on the free energy equilibrium principle and the thermodynamics of first and second law,and the phenomenological equations,the isothermal non-equilibrium thermodynamics flow model is established.The migration of pore solvent and solute in shale formations is comprehensively analyzed under the mechanical and chemical coupling condition.The results show that solute diffusion,which is caused by drilling fluid invasion,has a significant influence on the distribution of pore pressure.The slower the solute diffusion,the larger the efficiency of the membrane,the smaller the porosity,the higher the dissociation coefficient and the bigger the chemical potential of pore fluids,the larger the pore pressure variation will be.Secondly,based on the isothermal non-equilibrium thermodynamics model,considering the effect of temperature,the coupled chemo-poro-thermo-mechanical percolation model is derived.The numerical solution is solved.The pore pressure distribution and the sensitivity of controlling factors under the condition of different temperature difference between shale formations and drilling fluid is quantitatively analyzed.The temperature difference between the drilling fluid and the formation,thermal diffusivity and the thermo-osmosis coefficient have great effects on pore pressure distribution in shale formations.The pore pressure increases significantly,with high-temperature drilling fluids,low thermal diffusivity of formations or high thermo-osmosis coefficient.Thirdly,based on the isothermal non-equilibrium thermodynamics flow model,considering heat exchange between drilling fluids and formations,the rock matrix deformation,formation water content diffusion,change of the formation strength,and the porous elastic fluid-solid coupling theory,the non-isothermal multi-field coupling model of time dependent wellbore instability in shale formations has been established.The mathematical model includes some sub-models which describe different physical phenomena.The percolation model includes the influential term of rock deformation;meanwhile,the rock deformation model also has the influential term of fluid seepage.At the same time,the formation strength are influenced by temperature,pore pressure and chemical coupling effect.All these effects signify that the wellbore stability problem of shale formations is affected by multiple factors.The solution of the finite element method for the wellbore stability mathematical model is then carried out.In the spatial domain the model is discretized by the Galerkin principle,and in the time domain,the model is discretized with the fully implicit method.A weak form for the non-linear solution procedure of the finite element method is obtained.Then a numerical simulator of wellbore stability in shale formations is developed,and the validation is carried out.Finally,with the developed simulator,the time dependent wellbore instability of shale formations is numerically analyzed.The results show that,in the A block,the delayed time of the wellbore instability are respectively 2.5 and 8 days during horizontal drilling with the finely dispersed polymer drilling fluid and compound salt drilling fluid with the density of 1.2g/cm3,and the wellbore enlargement ratio after 10-day soaking is only 9%using oil-based drilling fluids with the same density,which indicates the delayed time is more than 10 days and the oil-based drilling fluid is hence optimal.