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.

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.

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.

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.

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.

Wellbore Stability Problems in Deepwater Gas Wells

The analysis of wellbore stability in deepwater gas wells is vital for effective drilling operations, especially in deepwater remote areas and for modern drilling technologies. Wellbore stability problems usually occur when drilling through hydrocarbon formations such as shale, unconsolidated sandstone, fractured carbonate formations and HPHT formations with narrow safety mud window. These problems can significantly affect drilling time, costs and the whole drilling operations. In deepwater gas wells, there is also the possible of gas hydrate problems because of the low temperature and high pressure conditions of the environment as well as the coexistence of gas and water inside the wellbore. These hydrates can block the mud line, surface choke line and even the BOP stack if no hydrate preventive measures are considered. In addition, the dissociation of these hydrates in the wellbore may gasify the drilling fluid and reduce drilling mud density, hydrostatic pressure, change mud rheology and cause wellbore instabilities. Traditional wellbore stability analysis considered the formation to be isotropic and assumed that the rock mechanical properties are independent of in-situ stress direction. This assumption is invalid for formations with layers or natural fractures because the presence of these geological features will influence rock anisotropic properties, wellbore stress concentration and failure behavior. This is a complicated phenomenon because the stress distribution around a wellbore is affected by factors such as rock properties, far-field principal stresses, wellbore trajectory, formation pore pressure, reservoir and drilling fluids properties and time. This research work reviews the major causes of wellbore stability problems in deepwater gas wells and outlines different preventive measures for effective drilling operation, because real-time monitoring of drilling process can provide necessary information for solving any wellbore stability problems in a short time.

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.

Wellbore drift flow relation suitable for full flow pattern domain and full dip range

Aiming at the simulation of multi-phase flow in the wellbore during the processes of gas kick and well killing of complex-structure wells(e.g.,directional wells,extended reach wells,etc.),a database including 3561 groups of experimental data from 32 different data sources is established.Considering the effects of fluid viscosity,pipe size,interfacial tension,fluid density,pipe inclination and other factors on multi-phase flow parameters,a new gas-liquid two-phase drift flow relation suitable for the full flow pattern and full dip range is established.The distribution coefficient and gas drift velocity models with a pipe inclination range of-90°–90°are established by means of theoretical analysis and data-driven.Compared with three existing models,the proposed models have the highest prediction accuracy and most stable performance.Using a well killing case with the backpressure method in the field,the applicability of the proposed model under the flow conditions with a pipe inclination range of-90°–80°is verified.The errors of the calculated shut in casing pressure,initial back casing pressure and casing pressure when adjusting the displacement are 2.58%,3.43%,5.35%,respectively.The calculated results of the model are in good agreement with the field backpressure data.

Prediction of wax precipitation region in wellbore during deep water oil well testing

During deep water oil well testing, the low temperature environment is easy to cause wax precipitation, which affects the normal operation of the test and increases operating costs and risks. Therefore, a numerical method for predicting the wax precipitation region in oil strings was proposed based on the temperature and pressure fields of deep water test string and the wax precipitation calculation model. And the factors affecting the wax precipitation region were analyzed. The results show that: the wax precipitation region decreases with the increase of production rate, and increases with the decrease of geothermal gradient, increase of water depth and drop of water-cut of produced fluid, and increases slightly with the increase of formation pressure. Due to the effect of temperature and pressure fields, wax precipitation region is large in test strings at the beginning of well production. Wax precipitation region gradually increases with the increase of shut-in time. These conclusions can guide wax prevention during the testing of deep water oil well, to ensure the success of the test.

Geomechanics involved in gas hydrate recovery

Gas hydrate is regarded as a promising energy owing to the large carbon reserve and high energy density.However,due to the particularity of the formation and the complexity of exploitation process,the commercial exploitation of gas hydrate has not been realized.This paper reviews the physical properties of gas hydratebearing sediments and focuses on the geomechanical response during the exploitation.The exploitation of gas hydrate is a strong thermal–hydrological–mechanical–chemical(THMC)coupling process:decomposition of hydrate into water and gas produces multi-physical processes including heat transfer,multi-fluid flow and deformation in the reservoir.These physical processes lead to a potential of geomechanical issues during the production process.Frequent occurrence of sand production is the major limitation of the commercial exploitation of gas hydrate.The potential landslide and subsidence will lead to the cessation of the production and even serious accidents.Preliminary researches have been conducted to investigate the geomechanical properties of gas hydrate-bearing sediments and to assess the wellbore integrity during the exploitation.The physical properties of hydrate have been fully studied,and some models have been established to describe the physical processes during the exploitation of gas hydrate.But the reproduction of actual conditions of hydrate reservoir in the laboratory is still a huge challenge,which will inevitably lead to a bias of experiment.In addition,because of the effect of microscopic mechanisms in porous media,the coupling mechanism of the existing models should be further investigated.Great efforts,however,are still required for a comprehensive understanding of this strong coupling process that is extremely different from the geomechanics involved in the conventional reservoirs.

Effects of instantaneous shut-in of high production gas well on fluid flow in tubing

As the classical transient flow model cannot simulate the water hammer effect of gas well, a transient flow mathematical model of multiphase flow gas well is established based on the mechanism of water hammer effect and the theory of multiphase flow. With this model, the transient flow of gas well can be simulated by segmenting the curved part of tubing and calculating numerical solution with the method of characteristic curve. The results show that the higher the opening coefficient of the valve when closed, the larger the peak value of the wellhead pressure, the more gentle the pressure fluctuation, and the less obvious the pressure mutation area will be. On the premise of not exceeding the maximum shut-in pressure of the tubing, adopting large opening coefficient can reduce the impact of the pressure wave. The higher the cross-section liquid holdup, the greater the pressure wave speed, and the shorter the propagation period will be. The larger the liquid holdup, the larger the variation range of pressure, and the greater the pressure will be. In actual production, the production parameters can be adjusted to get the appropriate liquid holdup, control the magnitude and range of fluctuation pressure, and reduce the impact of water hammer effect. When the valve closing time increases, the maximum fluctuating pressure value of the wellhead decreases, the time of pressure peak delays, and the pressure mutation area gradually disappears. The shorter the valve closing time, the faster the pressure wave propagates. Case simulation proves that the transient flow model of gas well can optimize the reasonable valve opening coefficient and valve closing time, reduce the harm of water hammer impact on the wellhead device and tubing, and ensure the integrity of the wellbore.

Wellbore temperature distribution during drilling of natural gas hydrate formation in South China sea

The natural gas hydrate resources in the South China Sea alone are about 85 trillion cubic meters.In the drilling process of marine gas hydrate,the natural gas hydrate will decompose and produce gas,as the rising of temperature and dropping of the pressure in the annulus.This process will have a significant impact on drilling safety.Therefore,it is necessary to study the wellbore temperature distribution during the drilling of marine hydrate layer.In this paper,the wellbore temperature distribution of safe drilling in hydrated formation is taken as the research goal,and the research status of relevant domestic and international wellbore temperatures was investigated.According to the characteristics of the marine environment and reservoir-forming characteristics of hydrate reservoirs in the South China Sea,the wellbore temperature distribution model of offshore drilling wellbore under the condition of hydrate decomposition was established.The temperature distribution curve of drilling straight wellbore in hydrate layer of South China Sea was obtained.When drilling the hydrate reservoir,the distribution regularity of the wellbore temperature is similar to that of the conventional offshore drilling wellbore.However,the temperature of the wellbore annulus near the hydrate decomposition site is lower than the ambient temperature,mainly due to the hydrate decomposition endothermic.In this paper,the sensitivity analysis of several main parameters of the wellbore temperature distribution of drilling straight wellbore in hydrate layer of South China Sea was carried out.Through the conduction of experiment and numerical simulation,we have get some new findings:(1)The hydrate saturation has little effect on the wellbore temperature;(2)As the drilling fluid displacement increases,the annulus temperature of the wellbore above the mudline increases,and the temperature of the wellbore below the mudline decreases continuously;(3)As the density of the drilling fluid increases,the temperature at the wellhead decreases,and the temperature at the bottom of the well increases slightly;(4)The greater the rate of penetration of the well,the temperature at the upper part of the wellbore decreases,and the temperature at the bottom of the wellbore increases;Among them,the penetration rate has the most obvious effect on the annular temperature.The results are expected to be helpful to guide the drilling process of marine gas hydrate and offer some references.

Calculation of safe drilling mud density window for shale formation by considering chemo-poro-mechanical coupling effect

It is difficult to define safe drilling mud density window for shale sections.To solve this problem,the general Biot effective stress principle developed by Heidug and Wong was modified.The Weibull statistical model was used to characterize the hydration strainrelated strength damage.Considering drilling fluid sealing barrier on shale,a calculation method of safe drilling mud density has been established for shale formation under drilling fluid sealing-inhibition-reverse osmosis effect,combined with a flow-diffusion coupling model.The influence of drilling fluid sealing and inhibiting parameters on safe drilling mud density window was analyzed.The study shows that enhancing drilling fluid sealing performance can reduce the pore pressure transmission and solute diffusion;the inhibiting performance of drilling fluid,especially inhibition to strength damage,is crucial for the wellbore collapse pressure of shale section with significant hydration property.The improvement of drilling fluid sealing and inhibition performance can lower collapse pressure and enhance fracturing pressure,and thus making the safe drilling fluid density window wider and the collapse period of wellbore longer.If there is osmosis flow in shale,induced osmosis flow can make the gap between collapse pressure and fracturing pressure wider,and the stronger the sealing ability of drilling fluid,the wider the gap will be.The safe drilling mud density window calculation method can analyze the relationships between collapse pressure,fracturing pressure and drilling fluid anti collapse performance,and can be used to optimize drilling fluid performance.

A large-scale experimental simulator for natural gas hydrate recovery and its experimental applications

To facilitate the recovery of natural gas hydrate(NGH)deposits in the South China Sea,we have designed and developed the world's largest publicly reported experimental simulator for NGH recovery.This system can also be used to perform CO_(2) capture and sequestration experiments and to simulate NGH recovery using CH_(4)/CO_(2) replacement.This system was used to prepare a shallow gas and hydrate reservoir,to simulate NGH recovery via depressurization with a horizontal well.A set of experimental procedures and data analysis methods were prepared for this system.By analyzing the measurements taken by each probe,we determined the temperature,pressure,and acoustic parameter trends that accompany NGH recovery.The results demonstrate that the temperature fields,pressure fields,acoustic characteristics,and electrical impedances of an NGH recovery experiment can be precisely monitored in real time using the aforementioned experimental system.Furthermore,fluid production rates can be calculated at a high level of precision.It was concluded that(1)the optimal production pressure differential ranges from 0.8 to 1.0 MPa,and the wellbore will clog if the pressure differential reaches 1.2 MPa;and(2)during NGH decomposition,strong heterogeneities will arise in the surrounding temperature and pressure fields,which will affect the shallow gas stratum.

Gas Flow in a Stratified Porous Medium with Crossflow

A new model called semi-permeable wall model is presented for multilayer gas reservoir. The model is used to study the influence of crossflow on pressure transient well tests and other single-phase flow problems. It is suggested here to use this model to approximate the actual multilayer gas reservoir, so that the problem is greatly simplified mathematically. Its differential equation is established here for multilayer gas reservoirs, and is linearized by normalized pseudo pressure and pseudo time. Simulation program is developed by finite-difference method when all layers are perforated. The feature of wellbore pressure and rate is clarified by analyzing the results of numerical simulation.