Wellbore Flow Research Articles

Estimation of Parameters for Non-Equilibrium Phase Transitions during the Flow of Oil and Gas Mixtures

Problems of unsteady gas-liquid flows in wellbores with phase transitions are common for hydrocarbon production and well drilling. Typically, flow in wellbores is sufficiently fast which requires taking into account the non-equilibrium nature of phase transitions. The set of equations describing conservation of mass for components and momentum conservation for the mixture is supplemented by the relaxation equation for concentration of gas dissolved in the liquid. It is known that the characteristic times of gas evolution from the liquid and gas dissolution in the liquid differ significantly and depend on fluid properties, thermobaric conditions, and the flow pattern. Therefore, obtaining estimates of relaxation times for real flows turns to be a difficult problem. In this study, we propose a method for estimating the characteristic relaxation times for gas evolution and dissolution during the gas-liquid flow in a well. The method combines the solution of the convective diffusion equation for the growth/collapse of a vapor bubble in a liquid with the current parameters of the gas-liquid flow. Estimates of the relaxation times for the bubbly flow (small bubbles, gas evolution predominates) and slug flow (large bubbles, dissolution predominates), as functions of time from the beginning of the process, are obtained for the parameters of a real flow in a wellbore. It is shown that the obtained dependencies are consistent with the typical scaling of the diffusion process with respect to the size of bubbles. The results are important for mathematical simulation of gas-liquid flows in wellbores during hydrocarbon production, as well as for calculation of the gas-kick process during well drilling with oil-based muds.

An optimization method of horizontal well completion control water and sand

With the development and maturity of horizontal well drilling and completion technology, horizontal wells are widely used in various reservoirs and have achieved good development results. Due to horizontal wells in the reservoir through a long distance, horizontal section of the reservoir physical property heterogeneity, water avoidance height difference and horizontal wellbore flow with toe effect, leading to production pressure difference and water breakthrough time in all parts of the shaft is different, the level of sand and bottom water cresting is strong heterogeneity, oil well early water breakthrough and local a large amount of sand production, the serious influence of horizontal well production and development of comprehensive benefits. In this paper, based on the prediction model of critical production pressure difference of sand production in horizontal wells and the prediction model of water appearance time of horizontal Wells in bottom water reservoir, the critical production pressure difference and water appearance time of sand production in each micro-element section are quantitatively determined along the horizontal well section, so as to form a design method of horizontal well completion that takes water and sand control into account. And ICD horizontal well completion method as the research object, water breakthrough time, yield as the optimization goal, control sand as constraint conditions, with each section down into the number of ICD string and nozzle sizes as design variables, the ICD horizontal well completion parameters established multi-objective optimization model, obtained the comprehensive consideration of water control sand control effect of the optimal ICD completion program.

Phase Equilibrium of Methane Hydrate in Aqueous Solutions of Clay Stabilizers

The effects of high concentrations of clay stabilizers in drilling and fracturing fluids on wellbore flow safety and natural gas hydrate exploitation have gained recent interest. This study investi...

Research on the Fluid Flow Characteristics in the Process of Pump Closing in Cementing

An instantaneous change of displacement during the cementing pump closing in the process of cementing in formations with a narrow density window may cause flow and pressure fluctuations and affect the wellbore safety and annulus pressure stability. Therefore, it is important to study the wellbore fluid flow characteristics in the process of cementing pump closing. In this paper, the authors have established control equations for the wellbore fluid flow in the process of instantaneous cementing pump closing and have determined the solution method and boundary conditions for the derived equations. The corresponding calculation software has been developed, and the fluid flow characteristics in the process of the cementing pump closing have been analyzed based on the practical calculation. This research may have important practical significance for optimizing the closing operation parameters in the process of cementing.

Внедрение инновационного программно-аппаратного комплекса пассивной акустики для диагностики технического состояния скважин

To ensure operational stability of the unified gas supply system depending on the seasonal gas demand fluctuations, the underground gas storage facilities are effectively used. Well integrity diagnostics using the advanced logging techniques facilitate timely identification of potential problems (pinpointing cross-flows behind casing, detecting leaks in production casing and other well construction components, locating sustained annulus pressure sources etc.), and, thereby extension of the safe operation life of functioning of the underground gas storage facilities. The results of the complex of field and geophysical studies in several underground gas storage wells are given in this article. Different types of the underground gas storages are reviewed: the ones located in an aquifer, salt dome, and mature field. The diagnostics was carried out based on the complex of downhole logging including a passive acoustic tool. The passive acoustics hardware and software technology can capture and interpret acoustic signals generated by the wellbore or reservoir flows. To recognise and interpret the captured signals, the temporal coherence algorithms, data wavelet filtration, and neural networks are used. The use of this technology allows to significantly improve the safety of well operation. The information obtained is used both in the preparation of industrial safety expert reports and for the development of effective programs for major repairs of the underground gas storage wells located in the depleted gas and water fields, as well as in the salt caverns. Hardware and software technology of passive acoustics is being used in almost all the major oil and gas provinces in the world, receiving recognition from the largest domestic and foreign companies, however, this is the first time that underground gas storage facilities are used to check the technical condition of the wells.

A Semi-Analytical Model Based on the Volumetric Source Method to Predict Acid Injection Profiles of Horizontal Wells in Carbonate Reservoirs

Abstract Acid treatment is an important measure to improve production for horizontal wells of carbonate reservoirs. Acid injection profile of horizontal wells (AIPHWs) is the most critical indicator of the success of the acidification. Currently, most previous works studied AIPHW based on the point source method. However, an inherent singularity exists in the point source solution, and hence, the calculation speed is too slow or the solution does not converge. To solve this problem, a semi-analytical model (coupling the wellbore flow model and reservoir seepage model) by the volumetric source method is presented to determine AIPHW in carbonate reservoirs. In this new coupled model, the permeability heterogeneity, formation contamination, acid-induced wormhole formation, and wellbore pressure drop are all considered. The results of the validations show that the results from the proposed method match well with the model results from the literature. Then, the effects of the acid injection flowrate, acid injection time, and permeability heterogeneity on the AIPHW are studied. According to the sensitivity analysis, we find that the disequilibrium degree of AIPHW becomes stronger as acid injection flowrate increases, acid injection time increases, and permeability heterogeneity coefficient increases. This study provides a guide for the design of horizontal well acidification and the evaluation of acid treatments of horizontal wells in carbonate reservoirs.

CO2 plume evolution in the saline aquifer under various injection operations for CCS

Carbon capture and storage (CCS) projects inject large amounts of CO2 into deep saline aquifers or depleted oil and gas reservoirs. This operation requires a leakage risk analysis for the injected CO2. The subsurface flow of CO2 at the injection formation is dependent on injection operations. This study proposes a method to combine a wellbore flow model and an analytical solution to the CO2 plume to investigate the influence of the injection temperature, pressure, and rate on the interface evolution between the CO2 and the brine. Using the wellbore flow model, the proposed mothed estimates the volume injection rate at the bottom hole under different injection parameters. Then it illustrates the effects of injection operations on the CO2 plume and its maximum radius at the interface between the caprock and formation. The results provide an estimation of the plume radius under different injection rate and duration that would help field operators manage leakage risks.

Theoretical study of conditions for generation of periodic wellbore flow due to inflow of a lower-enthalpy fluid

The authors have numerically simulated periodic wellbore flow due to inflow of a lower-enthalpy fluid at a shallow feed zone, while a higher-enthalpy fluid flows in at a deep feed zone. Typical flow patterns such as constant and periodic flows appear depending on dimensionless parameters, which has been investigated extensively. Generation of the periodic flow is governed by a simple nature described using a mean specific enthalpy of the shallow and deep reservoirs weighted by their productivity indices as well as a modification factor of the weight. The findings provide a useful guideline for forecasting generation of the periodic flow as well as developing an effective mitigation measure.

An improved drift-flux correlation for gas-liquid two-phase flow in horizontal and vertical upward inclined wells

Drift-flux model has been diffusely applied to characterize two-phase flow in pipes and wellbores owing to its accuracy and simplicity. The constitutive correlations used in the drift-flux model specifying the relative motion between the phases have been extensively investigated leading to the development of multitudinous correlations. However, previous studies reveal that most of the correlations can either be proper for limited two-phase flow conditions or the applicability is extended by increasing the complexity of the correlation. This study attempts to propose an improved drift-flux correlation concerning the distribution coefficient and drift velocity applying for a wide range of fluid properties, pipe orientations, and flow patterns without complicating the correlation. In this study, the drift velocity is defined in terms of pipe diameter, inclination angle, and void fraction while the distribution coefficient is correlated as a function of mixture Reynolds number and a Yield-Power-Law correlation in terms of void fraction. A comprehensive experimental database consisted of 1865 data records collected from 13 distinct sources is used for correlation parameterization and performance estimation. The proposed correlation shows comparable or even better performance in comparison to the other three well-established drift-flux correlations for predicting void fraction. The proposed correlation has also demonstrated outstanding performance in case where high liquid viscosity is involved.

A Comparative Study on Wellbore Pressure Transmission of Water and Carbon Dioxide during Fracturing

Hydraulic fracturing is one of the most effective ways for the development of unconventional oil and gas resources, CO2 has been regarded as an excellent alternative to water as its broad application prospects in unconventional reservoir development and benefit for CO2 utilization. The wellbore pressure will keep rising before fracture initiation during hydraulic fracturing, and fluid properties have significant influence of wellbore pressure transmission especially for CO2 fracturing. In this paper, a wellbore pressure transmission model based on the definition of fluid compressibility is established and coupled with wellbore flow model of compressible fluid to calculate the borehole pressurization rate for water-based and CO2 fracturing. The model has been verified by field data. The results show that the borehole pressurization rate for both water-based and CO2 fracturing reveal rising trend as pump rate increasing, and borehole pressurization rate of water-based fracturing is 10∼20 times that of CO2 fracturing with same pump rate. Moreover, the borehole pressurization rate increases linearly with pump rate of water-based fracturing, but excessive pump rate might reduce borehole pressurization rate of CO2 fracturing. The research results can simulate more perceptions for the optimizing design of actual hydraulic fracturing operating.

Seismic Imaging of Convective Geothermal Flow Systems to Increase Well Productivity

A core feature of convective geothermal resource production is wellbore energy flow Q ~ ρC x T x V. E.g., for wellbore fluid of volume heat capacity ρC ~ 4.3MJ/m3∙oC, temperature T ~ 230oC, and volumetric flow V ~ 50L/s, wellbore heat energy production is Q~ 50MWth ~ 5MWe. Wellbore fluid flow V =2πr0φv0ℓ for open wellbore length ℓ is given in turn by the spatially variable product crustal porosity times crustal fluid velocity v ≡ φv0 at the wellbore radius r0. For a geothermal wellbore to be productive (nominal Q ~ 5MWe), locally variable bulk inflow rates v = φv0 across crustal volumes of dimension ℓ must be adequate to sustain high wellbore flows (nominal V ~ 50L/s). Wide-ranging crustal well productivity statistics show that few crustal wells flow at these rates. This is not surprising as local bulk flow ~ 10-2 m/s needed for production wellbores is decades greater than ambient bulk fluid flow ~ 10-8-10-7m/s characteristic of natural convective geothermal systems. Such rare high flow locales must be found. While existing crustal surveys generally fix resource temperatures T with nominal 500m spatial resolution, as yet no survey technique provides data to locate production-grade flow rates at nominal ℓ ~ 50m spatial resolution. In consequence, many costly unproductive wells are drilled before sites of productive local geothermal fluid bulk flow v = φv0 ~ 10-2 m/s are located. A seismic survey methodology sensitive to crustal flow v = φv0 at ℓ ~25m resolution has evolved from multi-channel seismic reflection technology applied to the production of shale hydrocarbons. The field-proven seismic flow-imaging methodology can be adapted from sedimentary terrains to volcanic terrains through appropriate seismic refraction means for generating effective seismic velocity models for convective geothermal flow volumes. Numerical simulation for characteristic ambient crustal heterogeneous flow distributions v = φv0 at ℓ ~50m resolution shows that travel-time data for seismic source energy refracted from deep geothermal wellbores to surface seismic sensor arrays can replicate the multi-channel seismic flow-imaging capability demonstrated for shale formations. Multi-channel seismic reservoir flow monitor detection and mapping of flow-induced seismic emissions in shale formations can be adapted to achieve similar mapping of convective geothermal flow system structures with v = φv0 ~ 10-2m/s at nominal ℓ ~ 50m resolution. Such seismic emission flow structure maps can greatly reduce the uncertainty and hence the cost of drilling effective production wells at brownfield sites and assessment/development wells at greenfield sites

Modeling of asphaltene deposition during oil/gas flow in wellbore

Asphaltene deposition occurs in production lines and leads to a reduction in the production rate due to the contraction of the area. Besides, remedies to treat the deposition costs the industry a high expenditure because of the chemical and the physical removal techniques that may require a partial shutdown of the system. Therefore, it is crucial to accurately predict the rate of deposition to assist in minimizing and controlling this issue. To do so, factors contributing to the precipitation and deposition of asphaltenes must be accounted for, especially pressure and temperature. However, most models available in the literature assume a single-phase flow scenario to predict the thickness of asphaltene, which may lead to some discrepancies. Predicting pressure and temperature gradients in the wellbores during multi-phase flow using single-phase assumptions may cause a significant margin of error. In this study, a robust model is developed to predict the pressure, temperature, and asphaltene deposition simultaneously during multiphase flow in wellbores. The model predicts these variables with an acceptable margin of error when verified against experimental data available in the literature. It predicted the pressure against experimental data with a root-mean-square error of less than 1 psi for various flow patterns and the temperature profile with a root-mean-square error of 0.58 °F. Furthermore, a detailed analysis is conducted to investigate the effect of flow pattern, time, and gas flow rate on the thickness of the deposited layer of asphaltenes.

The performance of complex-structure fractured reservoirs considering natural and induced matrix block size, shape, and distribution

This paper introduces an analytical approach for the performance of the fractured reservoir considering the impact of the matrix block size, shape, and distribution. The objective is better understanding the roles of the variable interporosity flow systems, fracture flowing systems, and reservoir matrix heterogeneity in the responses of the wellbore pressure drop, flow rate, cumulative production, and productivity index. This understanding could help to eliminate the uncertainties and increase the accuracy in characterizing the conventional and unconventional reservoirs where very complex structures of a significant disorder in the matrix block size, shape and distribution could be existed in the porous media.The study uses the well documented multilinear flow model to describe the pressure distribution in the naturally fractured reservoirs depleted by multiple hydraulic fractures considering different matrix block sizes, shapes, and distributions. The analytical models of the flow rate, cumulative production, and the productivity index are also developed in this study from the multilinear flow model. The reservoirs of interest are assumed to have stimulated porous media extending between hydraulic fracture and unstimulated volume extending beyond the fracture tips toward the reservoir boundary. The unstimulated reservoir volume is assumed consisting of uniformly distributed single matrix block size and shape because there is no impact for the hydraulic fracturing process. While the stimulated reservoir volume is considered consisting of a variable matrix block size, shape, and distribution because of the impact of hydraulic fracture propagation. The petrophysical properties of the two porous media, as well as the storativity and interporosity flow coefficient, are assumed functions of the matrix characteristics in the two volumes. The matrix block dimensions (radius or length) are correlated exponentially with the distance from the hydraulic fracture face toward the no-flow boundary between these fractures. Three fracture-matrix fluid flux functions are developed for the reservoirs where the matrix blocks could have a spherical, slab, and cylindrical configuration.The study has reached several conclusions. A positive impact on the reservoir performance is seen when the matrix block size becomes small or when the small size matrix blocks control the distribution of the blocks in the porous media. Reservoir performance is enhanced also when there are several matrix block sizes compared to a single size or very few sizes. It is observed that the reservoirs with spherical blocks may give better performance than the reservoir with slab or cylindrical matrix blocks. In terms of matrix block size and distribution, heterogeneous reservoirs may have a higher productivity index than homogenous reservoirs. The variable matrix block size and distribution in the stimulated reservoir volume is more beneficial than the unstimulated volume. The novel point presented in this paper is developing several analytical models for the wellbore pressure drop, flow rate, cumulative production, and productivity index of hydraulically fractured reservoirs with a consideration given to the matrix block size, shape, and distribution.

Efficient History Matching of Thermally Induced Fractures Using Coupled Geomechanics and Reservoir Simulation

Waterflooding is a common recovery method used to maintain reservoir pressure and improve reservoir oil sweep efficiency. However, injecting cold water into a reservoir alters the state of in-situ formation stress and can result in the formation fracturing. In other words, it can cause the initiation and growth of thermally induced fractures (TIFs), even when the original fracture propagation pressure is not exceeded. TIFs can cause non-uniform distribution of the fluid flow in wellbores, a reduction in sweep efficiency, and early water breakthrough in nearby production wells. Modelling and history matching workflows that consider the dynamic nature of the TIF problem are critical. These workflows improve and validate reservoir and geomechanical models, identify and confirm observed TIF onset and propagation periods, and provide a history-matched sector model with the rock mechanical and thermal properties and stress gradients that can be used with confidence for subsequent studies. Modelling and the underlining assumptions of fluid flow in the TIF and reservoir matrix, as well as geomechanical changes due to cooling of the reservoir during injection, are detailed below. A 3D reservoir simulator coupled with 2D finite element TIF and geomechanical models were used to manually history match an injector (NI6) in the N Field sector reservoir model in which a TIF was observed. In this study, history matching workflows were developed to consider the dynamic nature of TIF development during waterflooding. The reservoir and geomechanical models were improved and validated via the observed TIF onset and propagation periods. The history-matched models produced can be used with confidence in subsequent studies. The practical workflows and guidelines developed here can be used in waterflooding operations during the modelling, design, and planning stages. The novelty of this study is the coupling approach of different complex processes done in order to capture dynamic changes during waterflooding operations. A similar history matching study could not be found in the literature.

Distributed Temperature Measurements Allow Fracture Diagnostics During Flowback

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 195221, “Fracture Diagnostics Using Distributed Temperature Measurements During Stimulation-Fluid Flowback,” by Yilin Mao, SPE, and Mehdi Zeidouni, SPE, Louisiana State University, and Caroline Godefroy, Interpretive Software Products, et al., prepared for the 2019 SPE Oklahoma City Oil and Gas Symposium, Oklahoma City, 9-10 April. The paper has not been peer reviewed. The significant temperature difference between the fractured and nonfractured regions during the stimulation-fluid flowback period can be useful for fracture diagnosis. Recent developments in downhole temperature-monitoring systems open new possibilities to detect these temperature variations to perform production-logging analyses. In the complete paper, the authors derive a novel analytical solution to model the temperature signal associated with the shut-in during flowback and production periods. The output of this work can contribute to production-logging, warmback, and wellbore-storage analyses to achieve successful fracture diagnostic. Introduction Information about individual fractures is critical in determining whether fracturing jobs have been successful or refracturing is required. Exploring new methods to evaluate fracture characteristics has been the focus of recent research activities. Triggered by field implementations and observations, research has been conducted to investigate temperature profiles during the early hydraulic fracturing and late production periods to characterize fractures. Current research on the use of temperature data to evaluate hydraulic fractures and reservoirs focuses on developing forward numerical and semianalytical models to predict temperature profiles during fracturing and production. As a prelude to the production period, stimulation fluid flowback is often performed after hydraulic fracturing operations to remove the remaining fluid and loosen proppant from the wellbore. Because recording the flowback operation may be required already by regulations, the cost of collecting data from the flowback period is minimal. As a result, ongoing research on analyzing data from the flowback period has aimed to diagnose fracture design and efficiency, characterize key reservoir properties from the chemical composition of the flowback fluids, and predict long-term production. Such efforts are based on the critical timing of the flowback period - a transition between what happened during completion and what will happen during production. The potential temperature modeling on the flowback period proposed here shares the same insight. Shortly after hydraulic fracturing stimulation, the temperature in the fractured region is still lower than in the nonfractured region. The objective of this work is to perform fracture diagnostics with the flowback temperature signal. The main objective is identifying inflow temperature from each of the fractures, critical as an input for production-logging-tool (PLT) analysis. Preliminary simulation studies found that the inflow temperature is identical to the surrounding fractured region temperature, which is masked by the heating effect introduced from wellbore fluid flow after the shut-in test (afterflow). Therefore, the authors propose analyzing this heating effect with analytical and numerical models, which are described in the complete paper. Once the heating effect is quantified, the inflow temperature for each fracture can be obtained.

Study on horizontal wellbore flow of supercritical carbon dioxide drilling

The filter loss in the long open hole interval is considerable during horizontal well drilling utilizing SC-CO2, which affects the wellbore temperature and pressure distribution. In this study, a wellbore flow and heat transfer model that considers fluid filtration characteristics, viscous friction heat production and CO2 physical properties is developed. The temperature and pressure are coupled using an alternating direction iterative method and the flow behavior of SC-CO2 in a horizontal wellbore is analyzed in detail. The results indicate that the mass flow rate loss factor can reach 12.33% at a well depth of 5000 m, but the CO2 leak-off has little influence on wellbore temperature–pressure distribution. In addition, phase transition occurs both in the drill pipe and the annulus during CO2 circulation, and wellbore pressure–temperature conditions are highly related to CO2 physical properties. The operating parameters affect the whole wellbore pressure level; however, they have little effect on the temperature of horizontal interval. Furthermore, the annulus pressure level and the open hole length of horizontal interval are major factors affecting CO2 leak-off. The model can help set the optimum drilling parameters during the actual SC-CO2 drilling process to effectively promote the technology.

A study on the thermal-hydrodynamical-coupled CO2 flow process in the Ordos CCS-geological-formation

Non-isothermal flow in wellbores and geological formations is an important process associated with geologic storage of CO2. Technically, simulation of it is a highly challenging task as it often encounters phase transition problems for the fluids involved, which may greatly influence the profiles of pressure, temperature, and flowrate along the wellbore and consequently changes the injectivity of the relevant gas injection. In this paper we present a coupled non-isothermal wellbore/reservoir model for simulating the relevant flow behaviors, in which the non-isothermal wellbore flow model CO2Well and the reservoir simulator TOUGH2/ECO2N are combined to form a novel coupled flow model. The model developed is compared and verified by the existing wellbore-reservoir simulator T2Well with two CO2 injection examples. These examples demonstrate that the present method has considerable computational advantages in simulating wellbore flows when phase transition occurs. We then apply this model to the Ordos CCS demonstration project in China, and investigate the sophisticated, thermal-hydrodynamically-coupled flow processes observed there owning to injection of the condensed, cold CO2 that was directly captured from a nearby coal liquefaction plant. The results obtained by the simulation, along with the relevant field observations, provide in-depth insights into the CO2 flow behaviors in both the wellbore and the geological formation. For example, the simulation revealed that, in the wellbore, the heat exchange between the injected CO2 and the surrounding rock plays a critical role for the temperature distribution. It was also observed that phase transition occurred in the transferred period between the injection time and the shut-in time. In addition, both the simulation and field observation showed that most CO2 injected entered the topmost layer due to the high transmissivity of the rock. The simulation also showed that the temperature-change zone travelled slower than the CO2 plume. For example, the CO2 plume extended to 430 m away from the injection site after 31 months of CO2 injection, while the temperature-change zone extended merely about 90 m away, much smaller than that of the CO2 plume. The simulation suggests that the injectivity at this site is about 0.83 kg/(MPa·s). The simulation also suggests that the injection temperature should be relatively high (e.g., above −3 °C if the injection rate is more than 9.45 kg/s) to avoid formation of CO2 hydrate in the subsurface.

Numerical study on competitive propagation of multi-perforation fractures considering full hydro-mechanical coupling in fracture-pore dual systems

Hydraulic fractures initialized from different perforations have different contributions to well production. Therefore, it is essential to study the competitive propagation of hydraulic fractures among multiple perforations. In this study, a fracture-pore flow model coupled with wellbore flow was developed and implemented in a three-dimensional numerical model to simulate multi-perforating hydraulic fracture propagation. The hydro-mechanical coupling effects in fractures and porous media were fully considered. The effectiveness of the model in simulating hydraulic fracture propagation, fracture reorientation and transient fluid leak-off was verified. Finally, a field hydraulic fracturing operation with multi-perforations in a tight reservoir was simulated. The sensitivities to the reservoir heterogeneity, fluid leak-off, layer inclination, well deviation and perforation friction were investigated in detail. This study revealed the following: 1) layered heterogeneities can cause strong competitive propagation of multi-cluster fractures; 2) flow rate in each perforation is controlled by perforation friction and stress shadow; 3) reservoir heterogeneity, layer inclination, and well deviation are major factors of the asymmetric fracture propagation; 4) the well deviation toward the direction of the minimum horizontal stress causes an asymmetric stress shadow and reduces the effective spacing of the perforations.

Optimization of the slotted liners parameters during dual tubing steam injection process

To study the distribution of steam parameters along the wellbore and the influence of slotted liners parameters on the effect of reservoir uniform preheating during the dual tubing steam injection process. Based on the structural characteristics of screen pipe completion and the simultaneous steam injection technology of long and short tubing, a coupled numerical model of fluid flow and heat transfer in reservoir and wellbore was established, and the model was solved by full implicit finite difference method and iterative technique. The results show that when the density, width and length of the slotted liners increase from 350 to 550/m, 0.20 to 0.40 mm and 35 to 75 mm, respectively, the difference of steam quality at the two ends of steam convergence position in the annuli increases by 0.41%, 2.26% and 1.71%, and the reservoir heating uniformity decreases by 1.49%, 2.68% and 2.08%, respectively. Optimizing the slotted liners parameters and reducing the steam quality difference at the convergence position of annuli can improve the uniform heating degree of reservoir along the horizontal wellbore.

On the validity of the two-fluid-KTGF approach for dense gravity-driven granular flows as implemented in ANSYS Fluent R17.2

As a subproblem of solid transport in wellbores, we have investigated the cliff collapse problem by means of the Two-Fluid-Model (TFM), where the rheological description of the second phase (sand) is governed by the Kinetic Theory of Granular Flows (KTGF) and additional closures from soil mechanics for dense (frictional) regions of the solid phase. Using ANSYS Fluent R17.2, we have studied the influence of the aspect ratio and scale of the initial cliff, the scale of the particle size, four different interstitial fluids (air, water, and two viscous but shear-thinning solutions), and the role of the initial condition (IC) of the solid volume fraction. The latter was evaluated by two different strategies: (1) Let solids settle to establish a compacted granular bed in dynamic equilibrium prior to allow the cliff to collapse and (2) simply patch the solid volume fraction into the computational domain at t = 0.While most of the simulations produced a final deposit featuring a slope, validation with experimentally obtained scaling laws from the literature was not comprehensively successful. The primary reason identified is that, at steady-state, for which a sloped deposit must exist, a thin layer at the top of the sediment bed remains flowing, yielding a scale-dependent disintegration of the cliff over longer periods of time which ultimately results in a flat bed. We suspect this phenomenon, hereafter termed top bed velocity defect, to be a consequence of the numerical solutions strategy of Fluent which may result in some momentum solid flux imbalance at top-bed regions where the gradient of the solids kinetic/collisional pressure is high.Comprehensive model tuning is required to yield a better physical representation of the IC. In addition, alternative closures for both solid frictional pressure and solid viscosity may be helpful to better replicate the experimental data. On the other hand, experimental spread and missing experimental data for the shear-thinning fluids requires more comprehensive experimental data for validation purposes.If the model in its current form is used for transport modeling of cuttings in wellbore flows, the velocity defect will lead to an unknown overestimation of the mass flux of solids. When it comes to the modeling of dune migration, the top bed velocity defect will likely cause disintegration of the dune over longer periods of time.