Effect of perforation density distribution on production of perforated horizontal wellbore

To address the issue of horizontal well production affected by the distribution of perforation density in the wellbore,a numerical model for simulating two-phase flow in a horizontal well is established under two perforation density distribution conditions(i.e.increasing the perforation density at inlet and outlet sections respectively).The simulation results are compared with experimental results to verify the reliability of the numerical simulation method.The behaviors of the total pressure drop,superficial velocity of air-water two-phase flow,void fraction,liquid film thickness,air production and liquid production that occur with various flow patterns are investigated under two perforation density distribution conditions based on the numerical model.The total pressure drop,superficial velocity of the mixture and void fraction increase with the air flow rate when the water flow rate is constant.The liquid film thickness decreases when the air flow rate increases.The liquid and air productions increase when the perforation density increases at the inlet section compared with increasing the perforation density at the outlet section of the perforated horizontal wellbore.It is noted that the air production increases with the air flow rate.Liquid production increases with the bubble flow and begins to decrease at the transition point of the slug-stratified flow,then increases through the stratified wave flow.The normalized liquid flux is higher when the perforation density increases at the inlet section,and increases with the radial air flow rate.

Integrated wellbore-reservoir-geomechanics modeling for enhanced interpretation of distributed fiber-optic strain sensing data in hydraulicfracture analysis

Fiber-optic distributed strain sensing(FO-DSS)has been successful in monitoring strain changes along horizontal wellbores in hydraulically fractured reservoirs.However,the mechanism driving the various FO-DSS responses associated with near-wellbore hydraulic fracture properties is still unclear.To address this knowledge gap,we use coupled wellbore-reservoir-geomechanics simulations to study measured strain-change behavior and infer hydraulic fracture characteristics.The crossflow among fractures is captured through explicit modeling of the transient wellbore flow.In addition,local grid refinement is applied to accurately capture strain changes along the fiber.A Base Case model was designed with four fractures of varying properties,simulating strain change signals when the production well is shut-in for 10 d after 240 d of production and reopened for 2 d.Strain-pressure plots for different fracture clusters were used to gain insights into inferring fracture properties using DSS data.When comparing the model with and without the wellbore,distinct strain change signals were observed,emphasizing the importance of incorporating the wellbore in FO-DSS modeling.The effects of fracture spacing and matrix permeability on strain change signals were thoroughly investigated.The results of our numerical study can improve the understanding of the relation between DSS signals and fracture hydraulic properties,thus maximizing the value of the dataset for fracture diagnostics and characterization.

Finite Element Method Simulation of Wellbore Stability under Different Operating and Geomechanical Conditions

The variation of the principal stress of formations with the working and geo-mechanical conditions can trigger wellbore instabilities and adversely affect the well completion.A finite element model,based on the theory of poro-elasticity and the Mohr-Coulomb rock damage criterion,is used here to analyze such a risk.The changes in wellbore stability before and after reservoir acidification are simulated for different pressure differences.The results indicate that the risk of wellbore instability grows with an increase in the production-pressure difference regardless of whether acidification is completed or not;the same is true for the instability area.After acidizing,the changes in the main geomechanical parameters(i.e.,elastic modulus,Poisson’s ratio,and rock strength)cause the maximum wellbore instability coefficient to increase.

The Wellbore Temperature and Pressure Behavior during the Flow Testing of Ultra-Deepwater Gas Wells

The transientflow testing of ultra-deepwater gas wells is greatly impacted by the low temperatures of seawater encountered over extended distances.This leads to a redistribution of temperature within the wellbore,which in turn influences theflow behavior.To accurately predict such a temperature distribution,in this study a comprehensive model of theflowing temperature and pressurefields is developed.This model is based on principles offluid mechanics,heat transfer,mass conservation,and energy conservation and relies on the Runge-Kutta method for accurate integration in time of the resulting equations.The analysis includes the examination of the influence of various factors,such as gasflow production rate,thermal diffusivity of the formation,and thermal diffusivity of seawater,on the temperature and pressure profiles of the wellbore.The keyfindings can be summarized as follows:1.Higher production rates during testing lead to increasedflowing temperatures and decreased pressures within the wellbore.However,in the presence of a seawater thermocline,a crossover inflowing temperature is observed.2.An increase in wellbore pressure is associated with larger pipe diameters.3.Greater thermal diffusivity of the formation results in more rapid heat transfer from the wellbore to the formation,which causes lowerflowing temperatures within the wellbore.4.In an isothermal layer,higher thermal diffusivity of seawater leads to increased wellboreflowing temperatures.Conversely,in thermocline and mixed layer segments,lower temperatures are noted.5.Production test data from a representative deep-water gas well in the South China Sea,used to calculate the bottom-seafloor-wellhead temperature and pressurefields across three operating modes,indicate that the average error in temperature prediction is 2.18%,while the average error in pressure prediction is 5.26%,thereby confirming the reliability of the theoretical model.

Wellbore Cleaning Degree and Hydraulic Extension in Shale Oil Horizontal Wells

The efficient development and exploitation of shale oil depends on long-distance horizontal wells. As the degreeof cleaning of the wellbore plays a key role in these processes, in this study, this problem is investigated experimentallyby focusing on the dimensionless cuttings bed height. A method is proposed to calculate the horizontalwellhydraulic extension taking into account the influence of the wellbore cleaning degree on the wellborepressure distribution and assess the effect of a variety of factors such as the bottom hole pressure, the circulatingpressure drop, the drilling pump performance and the formation properties. The analysis shows that the hydraulicextension of horizontal wells decreases with an increase in the cuttings bed height, and the higher the displacementof drilling fluid, the faster the hydraulic extension declines. The annular pressure drop of the horizontalsection increases with the increase of the cuttings bed height, resulting in a higher bottom-hole pressure. Severalarguments are provided to guide the safe drilling of shale oil horizontal wells and overcome the limits of currenttechnological approaches.

High-precision nonisothermal transient wellbore drift flow model suitable for the full flow pattern domain and full dip range

A reliable multiphase flow simulator is an important tool to improve wellbore integrity and production decision-making.To develop a multiphase flow model with high adaptability and high accuracy,we first build a multiphase flow database with 3561 groups of data and developed a drift closure relationship with stable continuity and high adaptability.Second,a high-order numerical scheme with strong fault capture ability is constructed by effectively combining MUSCL technology,van Albada slope limiter and AUSMV numerical scheme.Finally,the energy equation is coupled into the AUSMV numerical scheme of the drift flow model in the form of finite difference.A transient non-isothermal wellbore multiphase flow model with wide applicability is formed by integrating the three technologies,and the effects of various factors on the calculation accuracy are studied.The accuracy of the simulator is verified by comparing the measurement results with the blowout experiment of a full-scale experimental well.

Wellbore stability model in shale formation under the synergistic effect of stress unloading-hydration

According to the transversely isotropic theory and weak plane criterion, and considering the mechanical damages due to stress unloading and hydration during drilling, a shale wellbore stability model with the influence of stress unloading and hydration was established using triaxial test and shear test. Then, factors influencing the wellbore stability in shale were analyzed. The results indicate that stress unloading occurs during drilling in shale. The larger the confining pressure and axial stress, the more remarkable weakening of shale strength caused by stress unloading. The stress unloading range is positively correlated with the weakening degree of shale strength. Shale with a higher development degree of bedding is more prone to damage along bedding. In this case, during stress unloading, the synergistic effect of weak structural plane and stress unloading happens, leading to a higher weakening degree of shale strength and poorer mechanical stability, which brings a higher risk of wellbore instability. Fluid tends to invade shale through bedding, promoting the shale hydration. Hydration also can weaken shale mechanical stability, causing the decline of wellbore stability. Influence of stress unloading on collapse pressure of shale mainly occurs at the early stage of drilling, while the influence of hydration on wellbore stability mainly happens at the late stage of drilling. Bedding, stress unloading and hydration jointly affect the wellbore stability in shale. The presented shale wellbore stability model with the influence of stress unloading and hydration considers the influences of the three factors. Field application demonstrates that the prediction results of the model agree with the actual drilling results, verifying the reliability of the model.

Analysis of Wellbore Flow in Shale Gas Horizontal Wells

Theflow behavior of shale gas horizontal wells is relatively complex,and this should be regarded as the main reason for which conventional pipeflow models are not suitable to describe the related dynamics.In this study,numerical simulations have been conducted to determine the gas-liquid distribution in these wells.In particular,using the measuredflow pressure data related to 97 groups of shale gas wells as a basis,9 distinct pipeflow models have been assessed,and the models displaying a high calculation accuracy for different water-gas ratio(WGR)ranges have been identified.The results show that:(1)The variation law of WGR in gas well satisfies a power function relation.(2)The well structure is the main factor affecting the gas-liquid distribution in the wellbore.(3)The Beggs&Brill,Hagedorn&Brown and Gray models exhibit a high calculation accuracy.

Study on Horizontal Well Layout Boundary Considering Wellbore Pressure Loss

Based on the Dikken analytical calculation method of wellbore pressure loss under single-phase fluid and turbulent flow conditions, the correlation model between horizontal well output and horizontal section length and horizontal section distributed pressure difference is constructed. The influence degree of wellbore pressure loss on daily oil production of horizontal well, horizontal section pressure and production effect of horizontal well under different horizontal well lengths is analyzed, which provides certain reference for the design of horizontal well length and well layout.

Research regarding coal-bed wellbore stability based on a discrete element model

Wellbore instability is a key problem restricting efficient production of coal-bed methane. In order to perform thorough and systematic research regarding coal-bed wellbore stability problems, a new discrete element model which fully considers the features of cleat coal-beds is established based on the Kirsch equation. With this model, the safe pipe tripping speed, drilling fluid density window and coal- bed collapse/fracture pressure are determined; in addition, the relationships between pipe tripping speed and pipe size, cleat size, etc. and wellbore stability are analyzed in the coal-bed drilling and pipe tripping processes. The case studies show the following results： the wellbore collapses （collapse pressure： 4.33 MPa） or fractures （fracture pressure： 12.7 MPa） in certain directions as a result of swab or surge pressure when the pipe tripping speed is higher than a certain value; the cleat face size has a great influence on wellbore stability, and if the drilling fluid pressure is too low, the wellbore is prone to collapse when the ratio of the face cleat size to butt cleat size is reduced; however, if the drilling fluid pressure is high enough, the butt cleat size has no influence on the wellbore fracture; the factors influencing coal-bed stability include the movement length, pipe size, borehole size.

Near-wellbore fracture initiation and propagation induced by drilling fluid invasion during solid fluidization mining of submarine nature gas hydrate sediments

Drilling in a natural gas hydrate formation is challenging due to the poor consolidation of the formation and the potential evaporation of the hydrate.The unreasonable down-hole pressure of the drilling fluid can not only lead to the wellbore instability,but also change the predrilling condition of the natural gas hydrate formation,thus leading to an instable wellbore.In this paper,the integrated discrete element method(DEM)-computational fluid dynamics(CFD)work flow is developed to study the wellbore instability due to the penetration of the drilling fluid into the hydrate formation during crack propagations.The results show that the difference between in-situ stresses and overpressure directly affect the drilling fluid invasion behavior.The lower hydrate saturation leads to an easier generation of drilling fluid flow channels and the lower formation breakdown pressure.The breakdown pressure increases with the increase of hydrate saturation,this also indicates that hydrates can enhance the mechanical properties of the formation.The induced cracks are initially accompanied with higher pressure of the drilling fluid.According to the rose diagram of the fracture orientation,a wider orientation of the fracture distribution is observed at higher pressure of the invasion fluid.

Experimental Investigation of the Impact of Compression on the Petro-Physical and Micromechanical Properties of Wellbore Cement Containing Salt

In this study, we investigated the effect of compression on the micromechanical and the petro- physical properties of salted wellbore cement systems. The experiments were conducted using a customized bench scale model, which utilized an expandable tubulars simulating the compression of a previously cemented casing under field-like conditions. The “mini-wellbore model” sample consisted of a pipe inside pipe assembly with a cemented annulus. The cement samples were cured in a water bath for 28 days prior to the compression experiments to allow adequate hydration. The impact of compression on the cement’s petro-physical and mechanical properties was quantified by measuring the porosity, permeability and hardness of salt cement cores drilled parallel to the orientation of the pipe from the compacted cement sheath. Permeability (Core-flood) experiments were conducted at 21℃, 10,342 kPa confining pressure for a period of 120 minutes. During the core-flood experiments, conducted using Pulse-decay method, deionized water was flowed through cement cores to determine the permeability of the cores. The results obtained from these experiments confirmed that the compression of the cement positively impacted the cements ability to provide long term zonal isolation, shown by the effective reduction in porosity and permeability. Furthermore, the results confirm reduction in the detrimental effect of salt on the strength and stiffness in post-compression cement.

Numerical Analysis of Wellbore Instability in Gas Hydrate Formation During Deep-Water Drilling

Gas hydrate formation may be encountered during deep-water drilling because of the large amount and wide distribution of gas hydrates under the shallow seabed of the South China Sea. Hydrates are extremely sensitive to temperature and pressure changes, and drilling through gas hydrate formation may cause dissociation of hydrates, accompanied by changes in wellbore temperatures, pore pressures, and stress states, thereby leading to wellbore plastic yield and wellbore instability. Considering the coupling effect of seepage of drilling fluid into gas hydrate formation, heat conduction between drilling fluid and formation, hydrate dissociation, and transformation of the formation framework, this study established a multi-field coupling mathematical model of the wellbore in the hydrate formation. Furthermore, the influences of drilling fluid temperatures, densities, and soaking time on the instability of hydrate formation were calculated and analyzed. Results show that the greater the temperature difference between the drilling fluid and hydrate formation is, the faster the hydrate dissociates, the wider the plastic dissociation range is, and the greater the failure width becomes. When the temperature difference is greater than 7℃, the maximum rate of plastic deformation around the wellbore is more than 10%, which is along the direction of the minimum horizontal in-situ stress and associated with instability and damage on the surrounding rock. The hydrate dissociation is insensitive to the variation of drilling fluid density, thereby implying that the change of the density of drilling fluids has a minimal effect on the hydrate dissociation. Drilling fluids that are absorbed into the hydrate formation result in fast dissociation at the initial stage. As time elapses, the hydrate dissociation slows down, but the risk of wellbore instability is aggravated due to the prolonged submersion in drilling fluids. For the sake of the stability of the wellbore in deep-water drilling through hydrate formation, the drilling fluid with low temperatures should be given priority. The drilling process should be kept under balanced pressures, and the drilling time should be shortened.

Novel Water-Based Drilling and Completion Fluid Technology to Improve Wellbore Quality During Drilling and Protect Unconventional Reservoirs

The efficient exploration and development of unconventional oil and gas are critical for increasing the self-sufficiency of oil and gas supplies in China.However,such operations continue to face serious problems(e.g.,borehole collapse,loss,and high friction),and associated formation damage can severely impact well completion rates,increase costs,and reduce efficiencies.Water-based drilling fluids possess certain advantages over oil-based drilling fluids(OBDFs)and may offer lasting solutions to resolve the aforementioned issues.However,a significant breakthrough with this material has not yet been made,and major technical problems continue to hinder the economic and large-scale development of unconventional oil and gas.Here,the international frontier external method,which only improves drilling fluid inhibition and lubricity,is expanded into an internal-external technique that improves the overall wellbore quality during drilling.Bionic technologies are introduced into the chemical material synthesis process to imitate the activity of life.A novel drilling and completion fluid technique was developed to improve wellbore quality during drilling and safeguard formation integrity.Macroscopic and microscopic analyses indicated that in terms of wellbore stability,lubricity,and formation protection,this approach could outperform methods that use typical OBDFs.The proposed method also achieves a classification upgrade from environmentally protective drilling fluid to an ecologically friendly drilling fluid.The developed technology was verified in more than 1000 unconventional oil and gas wells in China,and the results indicate significant alleviation of the formation damage attributed to borehole collapse,loss,and high friction.It has been recognized as an effective core technology for exploiting unconventional oil and gas resources.This study introduces a novel research direction for formation protection technology and demonstrates that observations and learning from the natural world can provide an inexhaustible source of ideas and inspire the creation of original materials,technologies,and theories for petroleum engineering.

An analytical solution to wellbore stability using Mogi-Coulomb failure criterion

Deep wellbores/boreholes are generally drilled into rocks for oil and gas exploration,monitoring of tectonic stresses purposes.Wellbore and tunnel in depth are generally in true triaxial stress state,even if the ground is under axisymmetric loading condition.Stability of such wellbores is very critical and collapse of wellbore must be avoided.Mogi-Coulomb failure criterion is a better representation of rock strength under true triaxial condition.In this paper,an analytical solution is proposed using Mogi-Coulomb failure criterion.The solution is obtained for rock mass exhibiting elastic-perfectly plastic or elastic-brittle-plastic behaviour considering in-plane isotropic stresses.The proposed solution is then compared with exact analytical solution for incompressible material and experimental results of thickwall cylinder.It is shown that the results obtained by the proposed analytical solution are in good agreement with the experimental results and exact analytical solution.A reduction of about 13%e20%in plastic zone from the proposed closed-form solution is observed,as compared to the results from the finite element method(FEM)based Mohr-Coulomb criterion.Next,the influences of various parameters such as Poisson’s ratio,internal pressure(mud weight),dilation angle,and out-of-plane stress are studied in terms of stress and deformation responses of wellbore.The results of the parametric study reveal that variation in the out-of-plane stress has an inverse relation with the radius of plastic zone.Poisson’s ratio does not have an appreciable influence on the tangential stress,radial stress and radial deformation.Dilation angle has a direct relation with the deformation.Internal pressure is found to have an inverse relation with the radial deformation and the radius of plastic zone.

The performance of stochastic designs in wellbore drilling operations

Wellbore drilling operations frequently entail the combination of a wide range of variables. This is underpinned by the numerous factors that must be considered in order to ensure safety and productivity. The heterogeneity and sometimes unpredictable behaviour of underground systems increases the sensitivity of drilling activities. Quite often the operating parameters are set to certify effective and efficient working processes. However, failings in the management of drilling and operating conditions sometimes result in catastrophes such as well collapse or fluid loss. This study investigates the hypothesis that optimising drilling parameters, for instance mud pressure, is crucial if the margin of safe operating conditions is to be properly defined. This was conducted via two main stages： first a deterministic analysis--where the operating conditions are predicted by conventional modelling procedures--and then a probabilistic analysis via stochastic simulations--where a window of optimised operation conditions can be obtained. The outcome of additional stochastic analyses can be used to improve results derived from deterministic models. The incorporation of stochastic techniques in the evaluation of wellbore instability indicates that margins of the safe mud weight window are adjustable and can be extended considerably beyond the limits of deterministic predictions. The safe mud window is influenced and hence can also be amended based on the degree of uncertainty and the permissible level of confidence. The refinement of results from deterministic analyses by additional stochastic simulations is vital if a more accurate and reliable representation of safe in situ and operating conditions is to be obtained during wellbore operations.

Fabrication of a Hydrophobic Hierarchical Surface on Shale Using Modified Nano-SiO_(2)for Strengthening the Wellbore Wall in Drilling Engineering

Wellbore stability is essential for safe and efficient drilling during oil and gas exploration and development.This paper introduces a hydrophobic nano-silica(HNS)for use in strengthening the wellbore wall when using a water-based drilling fluid(WBF).The wellbore-strengthening performance was studied using the linear swelling test,hot-rolling recovery test,and compressive strength test.The mechanism of strengthening the wellbore wall was studied by means of experiments on the zeta potential,particle size,contact angle,and surface tension,and with the use of a scanning electron microscope(SEM).The surface free energy changes of the shale before and after HNS treatment were also calculated using the contact angle method.The experimental results showed that HNS exhibited a good performance in inhibiting shale swelling and dispersion.Compared with the use of water,the use of HNS resulted in a 20%smaller linear swelling height of the bentonite pellets and an 11.53 times higher recovery of water-sensitive shale—a performance that exceeds those of the commonly used shale inhibitors KCl and polyamines.More importantly,the addition of HNS was effective in preventing a decrease in shale strength.According to the mechanism study,the good wellbore-strengthening performance of HNS can be attributed to three aspects.First,the positively charged HNS balances parts of the negative charges of clay by means of electrostatic adsorption,thus inhibiting osmotic hydration.Second,HNS fabricates a lotus-leaf-like surface with a micro-nano hierarchical structure on shale after adsorption,which significantly increases the water contact angle of the shale surface and considerably reduces the surface free energy,thereby inhibiting surface hydration.Third,the decrease in capillary action and the effective plugging of the shale pores reduce the invasion of water and promote wellbore stability.The approach described herein may provide an avenue for inhibiting both the surface hydration and the osmotic hydration of shale.

Effects of creep characteristics of natural gas hydrate-bearing sediments on wellbore stability

Natural gas hydrate(NGH)reservoirs consist of the types of sediments with weak cementation,low strength,high plasticity,and high creep.Based on the kinetics and thermodynamic characteristics of NGH decomposition,herein a heat-fluid-solid coupling model was established for studying the wellbore stability in an NGH-bearing formation to analyze the effects of the creep characteristics of NGH-bearing sediments during long-term drilling.The results demonstrated that the creep characteristics of sediments resulted in larger plastic yield range,thus aggravating the plastic strain accumulation around the wellbore.Furthermore,the creep characteristics of NGH-bearing sediments could enhance the effects induced by the difference in horizontal in situ stress,as a result,the plastic strain in the formation around the wellbore increased nonlinearly with increasing difference in in situ stress.The lower the pore pressure,the greater the stress concentration effects and the higher the plastic strain at the wellbore.Moreover,the lower the initial NGH saturation,the greater the initial plastic strain and yield range and the higher the equivalent creep stress.The plastic strain at the wellbore increased nonlinearly with decreasing initial saturation.

Mudcake effects on wellbore stress and fracture initiation pressure and implications for wellbore strengthening

Although a large volume of mudcake filtration test data is available in the literature, effects of mudcake on wellbore strengthening cannot be quantified without incorporating the data into a stress-analysis model. Traditional models for determining fracture initiation pressure （FIP） either consider a wellbore with an impermeable mudcake or with no mudcake at all. An analytical model considering permeable mudcake is proposed in this paper. The model can predict pore pressure and stress profiles around the wellbore, and consequently the FIP, for different mudcake thickness, permeability, and strength. Numerical examples are provided to illustrate the effects of these mudcake parameters. The results show that a low-permeability mudcake enhances FIP, mainly through restricting fluid seepage and pore pressure increase in the near- wellbore region, rather than by mudcake strength. Fluid loss pressure （FLP） should be distinguished from FIP when a mudcake is present on the wellbore wall. Fracture may occur behind the mudcake at FIP without mudcake rupture. The small effect of mudcake strength on FIP does not mean its effect on FLP is small too. Mudcake strength may play an important role in maintaining integrity of the wellbore once a fracture has initiated behind the mudcake.

Fluid-solid coupling model for studying wellbore instability in drilling of gas hydrate bearing sediments

As the oil or gas exploration and development activities in deep and ultra- deep waters become more and more, encountering gas hydrate bearing sediments （HBS） is almost inevitable. The variation in temperature and pressure can destabilize gas hydrate in nearby formation around the borehole, which may reduce the strength of the formation and result in wellbore instability. A non-isothermal, transient, two-phase, and fluid-solid coupling mathematical model is proposed to simulate the complex stability performance of a wellbore drilled in HBS. In the model, the phase transition of hydrate dissociation, the heat exchange between drilling fluid and formation, the change of mechanical and petrophysical properties, the gas-water two-phase seepage, and its interaction with rock deformation are considered. A finite element simulator is developed, and the impact of drilling mud on wellbore instability in HBS is simulated. Results indicate that the re- duction in pressure and the increase in temperature of the drilling fluid can accelerate hydrate decomposition and lead to mechanical properties getting worse tremendously. The cohesion decreases by 25% when the hydrate totally dissociates in HBS. This easily causes the wellbore instability accordingly. In the first two hours after the formation is drilled, the regions of hydrate dissociation and wellbore instability extend quickly. Then, with the soaking time of drilling fluid increasing, the regions enlarge little. Choosing the low temperature drilling fluid and increasing the drilling mud pressure appropriately can benefit the wellbore stability of HBS. The established model turns out to be an efficient tool in numerical studies of the hydrate dissociation behavior and wellbore stability of HBS.