Numerical investigation of fluid phase momentum transfer in carbonate acidizing

This work mainly studies the effect of fluid phase momentum transfer mechanisms on the acidizing results,including the retardation effect of the porous structure and the interaction between the fluid phase,such as viscous dissipation and inertial effect.The results show that the acid fluid momentum transfer is influenced by the complex porous structure and fluid viscous dissipation.Eventually,the Stokes-Darcy equation is recommended to be adopted to describe the fluid phase momentum transfer in the following numerical simulation studies of the carbonate acidizing process.Based on this model,a parametric research is carried out to investigate the impact of acid on rock physical characteristics in the stimulation process.Increasing the acid concentration appears to minimize the quantity of acid consumed for the breakthrough.The acid surface reaction rate has a considerable impact on the pore volume to breakthrough and the optimum acid injection rate.The influence of permeability on the acidizing results basically shows a negative correlation with the injection rate.The difference between the acidizing curves of different permeability gradually becomes insignificant with the decrease in injection rate.The existence of isolated fracture and vug significantly reduces acid consumption for the breakthrough.

Characterization of complex hydraulic fractures in Eagle Ford shale oil development through embedded discrete fracture modeling

This study extends an integrated field characterization in Eagle Ford by optimizing the numerical reservoir simulation of highly representative complex fractured systems through embedded discrete fracture modeling(EDFM). The bottom-hole flowing pressure was history-matched and the field production was forecasted after screening complex fracture scenarios with more than 100 000 fracture planes based on their propped-type. This work provided a greater understanding of the impact of complex-fractures proppant efficiency on the production. After compaction tables were included for each propped-type fracture group, the estimated pressure depletion showed that the effective drainage area can be smaller than the complex fracture network if modeled and screened by the EDFM method rather than unstructured gridding technique. The essential novel value of this work is the capability to couple EDFM with third-party fracture propagation simulation automatically, considering proppant intensity variation along the complex fractured systems. Thus, this work is pioneer to model complex fracture propagation and well interference accurately from fracture diagnostics and pseudo 3 D fracture propagation outcomes for multiple full wellbores to capture well completion effectiveness after myriads of sharper field simulation cases with EDFM.

Low-tension gas process in high-salinity and low-permeability reservoirs

Polymer-based EOR methods in low-permeability reservoirs face injectivity issues and increased fracturing due to near wellbore plugging,as well as high-pressure gradients in these reservoirs.Polymer may cause pore blockage and undergo shear degradation and even oxidative degradation at high temperatures in the presence of very hard brine.Low-tension gas(LTG) flooding has the potential to be applied successfully for low-permeability carbonate reservoirs even in the presence of high formation brine salinity.In LTG flooding,the interfacial tension between oil and water is reduced to ultra-low values(10^-3 dyne/cm) by injecting an optimized surfactant formulation to maximize mobilization of residual oil post-waterflood.Gas(nitrogen,hydrocarbon gases or C02) is co-injected along with the surfactant slug to generate in situ foam which reduces the mobility ratio between the displaced(oil) and displacing phases,thus improving the displacement efficiency of the oil.In this work,the mechanism governing LTG flooding in low-permeability,high-salinity reservoirs was studied at a microscopic level using microemulsion properties and on a macroscopic scale by laboratory-scale coreflooding experiments.The main injection parameters studied were injected slug salinity and the interrelation between surfactant concentration and injected foam quality,and how they influence oil mobilization and displacement efficiency.Qualitative assessment of the results was performed by studying oil recovery,oil fractional flow,oil bank breakthrough and effluent salinity and pressure drop characteristics.

Identifying the dominant transport mechanism in single nanoscale pores and 3D nanoporous media

Gas transport mechanisms can be categorized into viscous flow and mass diffusion,both of which may coexist in a porous media with multiscale pore sizes.To determine the dominant transport mechanism and its contribution to gas transport capacity,the gas viscous flow and mass diffusion processes are analyzed in single nanoscale pores via a theoretical method,and are simulated in 3D nanoporous media via pore-scale lattice Boltzmann methods.The apparent permeability from the viscous flow and apparent diffusivity from the mass diffusion are estimated.A dimensionless parameter,i.e.,the diffusion-flow ratio,is proposed to evaluate the dominant transport mechanism,which is a function of the apparent permeability,apparent diffusivity,bulk dynamic viscosity,and working pressure.The results show that the apparent permeability increases by approximately two orders of magnitude when the average Knudsen number(Kn_(avg))of the nanoporous media or Knudsen number(Kn)of single nanoscale pores increases from 0.1 to 10.Under the same conditions,the increment in the apparent diffusivity is only approximately one order of magnitude.When Kn<0.01,the apparent permeability has a lower bound(i.e.,absolute permeability).When Kn>10,the apparent diffusivity has an upper bound(i.e.,Knudsen diffusivity).The dominant transport mechanism in single nanoscale pores is the viscous flow for 0.01<Kn<100,where the maximum diffusion-flow ratio is less than one.In nanoporous media,the dominant transport relies heavily on Kn_(avg) and the structural parameters.For nanoporous media with the pore throat diameter of 3 nm,Kn_(avg)=0.2 is the critical point,above which the mass diffusion is dominant;otherwise,the viscous flow is dominant.As Kn_(avg) increases to 3.4,the mass diffusion is overwhelming,with the maximum diffusion-flow ratio reaching ~4.

Key problems and solutions in supercritical CO2 fracturing technology

Supercritical CO2 fracturing is considered to be a new method for efficient exploitation of unconventional reservoirs,such as shale gas,coal bed methane,and tight sand stone gas.Supercritical CO2 has many special properties including low viscosity,high diffusion coefficient,and lack of surface tension,which brings about great advantages for fracturing.However,these properties also cause several problems,such as difficulty in proppant transportation,high friction loss,and high pump displacement.In this paper,the above problems were analyzed by combining field test with laboratory study and specific solutions to these problems are given.The high frictionloss in the pipeline could be reduced by developing a new drag reducing agent and selecting large-size casing.Besides,for the problem of poor capacity in proppant carrying and sand plug,the methods of adding tackifier into supercritical CO2,increasing pump displacement and selecting ultralow density proppants are proposed.Moreover,for the problem of fast leak-off and high requirement for pump displacement,the displacement can be increased or the pad fluid can be injected into the reservoir.After solving the above three problems,the field test of supercritical CO2 fracturing can be conducted.The research results can promote the industrialization process of supercritical CO2 fracturing.

A unified fractional flow framework for predicting the liquid holdup in two-phase pipe flows

Two-phase pipe flow occurs frequently in oil&gas industry,nuclear power plants,and CCUS.Reliable calculations of gas void fraction(or liquid holdup)play a central role in two-phase pipe flow models.In this paper we apply the fractional flow theory to multiphase flow in pipes and present a unified modeling framework for predicting the fluid phase volume fractions over a broad range of pipe flow conditions.Compared to existing methods and correlations,this new framework provides a simple,approximate,and efficient way to estimate the phase volume fraction in two-phase pipe flow without invoking flow patterns.Notably,existing correlations for estimating phase volume fraction can be transformed and expressed under this modeling framework.Different fractional flow models are applicable to different flow conditions,and they demonstrate good agreement against experimental data within 5%errors when compared with an experimental database comprising of 2754 data groups from 14literature sources,covering various pipe geometries,flow patterns,fluid properties and flow inclinations.The gas void fraction predicted by the framework developed in this work can be used as inputs to reliably model the hydraulic and thermal behaviors of two-phase pipe flows.