Wellbore Flow Research Articles

A modified comprehensive prediction model for wellbore temperature-pressure field and liquid loading of gas wells

Wellbore liquid loading is a severe problem in the late stage of natural gas production, and precise prediction of liquid loading is helpful for taking dewatering measures timely to avoid the related hazards. Based on the flow and heat transfer mechanisms of gas-liquid two-phase annular flow in wellbore, a new model for calculating temperature and pressure field of the gas well considering the effects of the velocity difference between the gas core and liquid film and the migration of liquid droplets was established first, which laid a foundation for the prediction of liquid loading in the whole wellbore. Then, based on the flow mechanism of liquid film, a liquid loading prediction model for the whole wellbore of gas well was established, with the zero shear force between tubing wall and liquid film under low liquid holdup and the critical liquid holdup of liquid film bridging and plugging gas core taken as criteria for judging liquid loading, and the coupling solution method for the above model was worked out. Production data pairs of gas wells were used to verify the reliability of the model. The results show that our model can accurately calculate the wellbore temperature and pressure of liquid-producing gas wells. The temperatures predicted by the model have a maximum relative error of 11. 86% and an average relative error of 5. 96%, while the pressures predicted have a relative error range from 0. 09% to 8. 42%. In terms of prediction accuracy and prediction error of gas well liquid loading state, the modified model has much more precise prediction results of liquid loading than three classical liquid loading models. Finally, the sensitivity analysis of liquid loading was carried out with an example. The research results can provide theoretical support for the early prediction of liquid loading and dewatering process in liquid-producing gas wells.

Heat Production Performance from an Enhanced Geothermal System (EGS) Using CO2 as the Working Fluid

CO2-based enhanced geothermal systems (CO2-EGS) are greatly attractive in geothermal energy production due to their high flow rates and the additional benefit of CO2 geological storage. In this work, a CO2-EGS model is built based on the available geological data in the Gonghe Basin, Northwest China. In our model, the wellbore flow is considered and coupled with a geothermal reservoir to better simulate the complex CO2 flow and heat production behavior. Based on the fractured geothermal reservoir at depths between 2900 m and 3300 m, the long-term (30-year) heat production performance is predicted using CO2 as the working fluid with fixed wellhead pressure. The results indicate that the proposed CO2-EGS will obtain an ascending heat extraction rate in the first 9 years, followed by a slight decrease in the following 21 years. Due to the significant natural convection of CO2 (e.g., low viscosity and density) in the geothermal reservoir, the mass production rate of the CO2-EGS will reach 150 kg/s. The heat extraction rates will be greater than 32 MW throughout the 30-year production period, showing a significant production performance. However, the Joule–Thomson effect in the wellbore will result in a drastic decrease in production temperature (e.g., a 62.6 °C decrease in the production well). This means that the pre-optimization analyses and physical material treatments are required during geothermal production using CO2 as the working fluid.

A model for proppant dynamics in a perforated wellbore

This paper presents a model to simulate behavior of particle-laden slurry in a horizontal perforated wellbore with the goal of quantifying fluid and particle distribution between the perforations. There are two primary phenomena that influence the result. The first one is the non-uniform particle distribution within the wellbore’s cross-section and how it changes along the flow. The second phenomenon is related to the ability of particles to turn from the wellbore to a perforation. Consequently, the paper considers both of these phenomena independently at first, and then they are combined to address the whole problem of flow in a perforated wellbore. A mathematical model for calculating the particle and velocity profiles within the wellbore is developed. The model is calibrated against available laboratory data for various flow velocities, particle diameters, pipe diameters, and particle volume fractions. It predicts a steady-state solution for the particle and velocity profiles, as well as it captures the transition in time from a given state to the steady-state solution. The key dimensionless parameter that quantifies the latter solution is identified and is called dimensionless gravity. When it is small, the particles are fully suspended and the solution is uniform. At the same time, when the aforementioned parameter is large, then the solution is strongly non-uniform and resembles a flowing bed state. A mathematical model for the problem of particle turning is developed and is calibrated against available experimental and computational data. The key parameter affecting the result is called turning efficiency. When the efficiency is close to one, then most of the particles that follow the fluid streamlines going into the perforation are able enter the hole. At the same time, zero efficiency corresponds to the case of no particles entering the perforation. Solutions for the both sub-problems are combined to develop a model for the perforated wellbore. Results are compared (not calibrated) to a series of laboratory and field scale experiments for perforated wellbores. Comparison with the available computational results is presented as well. In addition, the comparison is presented in view of the parametric space defined by the dimensionless gravity and turning efficiency. Such a description allows to explain seemingly contradictory results observed in different tests and also allows to highlight parameters for which perforation orientation plays a significant role.

Numerical Simulation and Experimental Investigation of Variable Mass Flow in Horizontal Wellbores: Single-Phase and Multiphase Analysis

Considering the current limitations and restricted scope of existing experiments, as well as the absence of corresponding numerical simulation verifications and comparisons, and the lack of actual case studies of variable mass flow calculation and comparison, this study focuses on high production oilfields in the Mideast and South China Sea. The objective is to investigate single-phase and multiphase variable mass flow through numerical and experimental simulations. The study develops linear regression equations to establish the relationship between the mixture pressure drop caused by side flow and the velocities of the main flow, as well as the ratio between side and main flow velocities. Actual calculations using these equations are provided. The comprehensive analysis reveals that, for a fixed total flow rate, an increase in the side versus main injection velocity ratio leads to an increase in pressure loss before and after the injection hole. In single-phase flow, the friction factor for side hole flow is generally higher than that for only axial main flow, with the same total flow rate. In multiphase flow, when the gas-liquid ratio (GLR) is relatively large, the side flow has minimal impact on pressure drop, while at lower GLR values, the side flow significantly increases the pressure drops. When predicting the pressure drop for single-phase variable mass flow in horizontal wellbores, it is appropriate to consider only the mixture pressure drop caused by the closest hole to the calculation section, assuming the injection hole flow rates are approximately equal. In terms of predicting the productivity of single-phase variable mass flow, it is crucial to consider the mixture pressure drop. Neglecting the mixture pressure drop can lead to relatively larger productivity prediction results, with potential production rate errors exceeding 50%. The accuracy of the prediction is influenced by the ratio of mixture pressure drop to production pressure differential, and the pressure along the external zone of the screen pipe is higher when considering the mixture pressure drop compared to when it is neglected. Additionally, the flow rate along the external zone of the screen pipe becomes more non-uniform when the mixture pressure drop is considered. Furthermore, the findings from the single-phase and multiphase flow experiments suggest that significant deviations in production rates may occur in scenarios with low gas-liquid ratio (GLR), highlighting the need for further investigation in this area.

A Model Based on the Random Forest Algorithm That Predicts the Total Oil–Water Two-Phase Flow Rate in Horizontal Shale Oil Wells

Due to variables like wellbore deviation variation and flow rate, the local flow velocity in the output wellbore of horizontal shale oil wells varied significantly at various points in the wellbore cross-section, making it challenging to calculate the total single-layer production with accuracy. The oil–water two-phase flow rate calculation techniques for horizontal wells developed based on particular flow patterns and array spinners had excellent applicability in their respective niches but suffered from poor generalizability and demanding experience levels for logging interpreters. In this study, we employed five spinners in a triangular walled array instrument to create the multi-decision tree after figuring out how many leaf nodes there were and examining the defining characteristics of the observed values gathered under various experimental setups. The construction of the entire oil–water two-phase flow prediction model was made possible when the random forest regression approach was used with it. The total oil–water flow rate at each perforated layer was predicted using the model in sample wells, and the mean square error with the third party’s interpretation conclusion was 1.42, indicating that the model had an excellent application effect. The approach, which offered a new interpretation method for calculating the oil–water two-phase flow rate of horizontal wells based on multi-location local flow rate, required less interpretation knowledge from the interpreter and had a stronger generalization capacity.

Simulation Experiment and Mathematical Model of Liquid Carrying in the Entire Wellbore of Shale Gas Horizontal Wells

Shale gas is mostly produced using horizontal wells, since shale gas reservoirs have low porosity and permeability. It is challenging to predict a horizontal well’s critical liquid-carrying gas flow rate because horizontal wells have more complicated well structures and gas–liquid two-phase pipe flows than vertical wells. In addition, there are significant differences between shale gas reservoirs and conventional natural gas reservoirs as well as dynamic changes in the liquid production rate. The majority of critical liquid-carrying models currently in use in engineering are based on the force analysis of droplets in the gas stream or liquid film on the pipe wall in annular-mist flow in the vertical wellbore. However, they do not take into account the impact of changes to the entire wellbore structure and dynamic changes in the liquid production rate on gas–liquid two-phase flow patterns and liquid carrying in the wellbore. In order to perform the critical gas velocity test for liquid carrying in the entire wellbore of horizontal wells, a visual liquid-carrying simulation experimental device for the entire wellbore of horizontal wells and a high-speed camera were used in this study. The onset of liquid accumulation was analyzed comprehensively according to the overall increase of the wellbore liquid and the change of the system pressure. A modified K–H wave theory liquid-carrying model was developed by taking into account the impacts of liquid production rate and well inclination angle based on the experimental data, the K–H wave theory, the cross-section actual gas velocity, and the angle correction correlation formula. The improved liquid-carrying model is in good accordance with the test findings, according to the experimental results. In Shunan Gas Mine, Sichuan, China, there are eight deep shale gas wells, which produced a total of 25 sets of tests. The modified model was used to forecast and diagnose the liquid-carrying capacity in the entire wellbore of these wells. The diagnosis results are in good agreement with the actual production situation, and the coincidence rate is 92%.

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

With the increasing global demand for oil and gas, the development of unconventional resources such as shale gas is becoming ever more important. The key to developing unconventional oil and gas resources lies in horizontal wells with multistage fracturing technology. In the process of horizontal well segmentation fracturing, the distribution of the proppant among multiple clusters has a significant influence on the fracturing effect. However, the influence of various factors on the entry of proppant into the perforation and then into the fracture along the wellbore is unclear. In this paper, based on the flow characteristics of proppants in fracturing fluids, we investigate the wellbore–perforation proppant transport using a Eulerian multiphase flow model. The effect of different factors on proppant entry into the perforation in horizontal wells is studied. We first verify that the computational fluid dynamics model satisfies the accuracy requirements for studying the sand-carrying efficiency of proppants in a perforation cluster. Second, the effects of the proppant size, proppant density, fracturing fluid viscosity, perforation diameter, and fracturing fluid flow rate on the proppant transport efficiency are investigated. Finally, a mathematical model of the sand-carrying efficiency is established by multivariate nonlinear fitting. The results show that the proppant size has a more significant effect on proppant settling at low wellbore flow rates. Increasing the diameter of the proppant particles can accelerate proppant settling. Higher wellbore flow rates tend to reduce the sand-carrying efficiency, although using a low-density proppant can mitigate the effect of the wellbore flow rate. At low wellbore flow rates, increasing the perforation size makes it easier for the proppant to enter bottom perforations. Increasing the fluid viscosity helps to distribute the proppant evenly between perforations in different directions, but this effect diminishes as the flow rate increases. Finally, a formula for the wellbore sand-carrying efficiency is obtained and validated, providing a basis for optimizing the distribution of the proppant in the perforation. The results from this paper enhance our understanding of the sand and fluid feeding patterns of each perforation cluster and provide direction for improving the construction process and enhancing the fracture inflow capacity.

Fluidic Diode AICD Characteristic Curve Testing and Mathematical Modeling

In order to investigate an efficient water control method suitable for the bottom water occurring during the production process of horizontal wells in bottom water reservoirs, the characteristic curves of a Fluidic Diode AICD (Automatic Inflow Control Device) were tested, and a mathematical modeling method is proposed. First, the working principle of a Fluidic Diode AICD was analyzed; subsequently, a Fluidic Diode AICD test platform was designed and built independently, and pressure test experiments of the Fluidic Diode AICD under different flow conditions were carried out to obtain characteristic curves of the Fluidic Diode AICD. Finally, a mathematical model of the flow–pressure drop characteristic curves of the Fluidic Diode AICD was developed and applied to the simulation of water control production in horizontal wells in bottom water reservoirs. The results of the study showed that the Fluidic Diode AICD produces a more significant pressure drop under high water content conditions, and has a better oil and water stabilization function in production. In this study, the reservoir flow, annulus flow, AICD flow, and horizontal wellbore flow are considered, and an integrated coupling model for horizontal wells in bottom water reservoirs is established. This study provides a basis for using Fluidic Diode AICDs in horizontal wells in bottom water reservoirs.

Investigation of flow regimes, pressure drop, void fraction, film thickness, friction factor and production of two-phase flow in a perforated horizontal wellbore

This study focuses on investigating the impact of flow patterns on production in perforated horizontal wellbores. According to experimental and numerical results, this paper discussion the behaviour of total pressure drop, mixture superficial velocity, void fraction, liquid film thickness, and production that occur with various flow patterns in a perforated horizontal pipe. The flow patterns were predicted experimentally and numerically using a pipe with a length of 3 m and an internal diameter of 0.0381 m, with two perforations of inside diameter 0.004 m with a phasing angle of °180, to simulate the complex flow in horizontal wellbores. Total pressure drop and liquid film thickness were reduced by increasing the radial air flow of the perforations. At the same time, void fraction and mixture superficial velocity were observed to increase. Additionally, the film thickness increased with the holdup fraction but decreased with the void fraction. The local friction factor reflected the behaviour of the mixture's superficial velocity during the region of the perforations. The friction factor with the perforated horizontal pipe was greater than that in the unperforated horizontal pipe. The liquid product increased with an increase in the mixture's superficial velocity, and the percentage amounts of production shown were 10%, 40%, and 75%, depending on the water's superficial velocity. The convergence between experimental and numerical results was good during the flow patterns (slug flow and stratified flow). In contrast, some differences in the static pressure drop behaviour occur during flow patterns (bubble flow, dispersed bubble flow, and stratified wave flow).

A Transient Productivity Prediction Model for Horizontal Wells Coupled with Oil and Gas Two-Phase Seepage and Wellbore Flow

Capacity prediction is the basis for the optimization of oil and gas well production work systems and parameter optimization design. Horizontal wells are becoming increasingly popular for oil and gas extraction. However, the seepage law of reservoirs produced with horizontal wells is more complicated than that of reservoirs produced with vertical wells, especially when the bottom hole flowing pressure or formation pressure is less than the saturation pressure of crude oil in the reservoir. Oil and gas two-phase seepage can occur in a part or all areas of the wellbore and reservoir. Because the oil and gas two-phase seepage characteristics of reservoir oil well production will be reduced—possibly greatly reduced—the formation seepage law is complex. Thus, it is very important to better predict the horizontal well capacity. To address this, a method and process of establishing a transient calculation model of two-phase flow in horizontal wells are introduced in detail from three aspects: fluid physical properties, reservoir oil and gas two-phase seepage, and the coupling model of the inflow performance and flow in the wellbore. The model is found to be reliable through verification with production data from five wells in two oilfields. The established model simplifies the reservoir model, does not involve very complex meshing, and only simulates one well. Therefore, the calculation speed will be faster than that of other reservoir numerical simulation methods under the same conditions.

Numerical simulations of supercritical carbon dioxide fracturing: A review

As an emerging waterless fracturing technology, supercritical carbon dioxide (SC-CO 2 ) fracturing can reduce reservoir damage and dependence on water resources, and can also promote the reservoir stimulation and geological storage of carbon dioxide (CO 2 ). It is vital to figure out the laws in SC-CO 2 fracturing for the large-scale field implementation of this technology. This paper reviews the numerical simulations of wellbore flow and heat transfer, fracture initiation and propagation, and proppant transport in SC-CO 2 fracturing, including the numerical approaches and the obtained findings. It shows that the variations of wellbore temperature and pressure are complex and strongly transient. The wellhead pressure can be reduced by tubing and annulus co-injection or adding drag reducers into the fracturing fluid. Increasing the temperature of CO 2 with wellhead heating can promote CO 2 to reach the well bottom in the supercritical state. Compared with hydraulic fracturing, SC-CO 2 fracturing has a lower fracture initiation pressure and can form a more complex fracture network, but the fracture width is narrower. The technology of SC-CO 2 fracturing followed by thickened SC-CO 2 fracturing, which combines with high injection rates and ultra-light proppants, can improve the placement effect of proppants while improving the complexity and width of fractures. The follow-up research is required to get a deeper insight into the SC-CO 2 fracturing mechanisms and develop cost-effective drag reducers, thickeners, and ultra-light proppants. This paper can guide further research and promote the field application of SC-CO 2 fracturing technology.

Laboratory Test of Fluid Physical Property Parameters of Well Fluid Containing CO2

Change regulation of the physical properties of fluid is key to accurately predicting multiphase fluid flow in the production wellbore of CO2 flooding reservoirs. Given the characteristics of significant changes in pressure, temperature, and CO2 content in the whole wellbore of production wells in CO2 flooding reservoirs, this paper systematically studied the change rules of volume factor, viscosity, density, and solubility of well fluid for pressure 5~30 MPa, temperature 20~120 °C, and CO2 content 10~90% through single degassing PVT experiments. According to the experimental results, the volume factor of crude oil increases first and then decreases with the pressure increase. At the bubble point pressure (20 MPa), the volume factor of crude oil can reach 1.89 at high temperatures. The volume factor can be increased from 1.28 to 1.44 at 8 MPa when the temperature increases from 20 °C to 120 °C. Under the bubble point pressure, the increase in pressure increases the solubility of CO2, and the viscosity of crude oil decreases rapidly. In contrast, above the saturation pressure, the increase in pressure increases the viscosity of crude oil. Under the freezing point temperature (24 °C), the viscosity of crude oil decreases sharply with increase in temperature. In contrast, above the freezing point temperature, the viscosity change of crude oil is not sensitive to temperature. The wellbore temperature has a significant impact on the density of the well fluid. At 5 MPa, the temperature increases from 20 °C to 120 °C, which can reduce the density of high CO2 crude oil from 0.93 g/cm3 to 0.86 g/cm3. The solubility of CO2 in crude oil is sensitive to pressure. When the pressure increases from 5 MPa to 15 MPa at 20 °C, the solubility increases by 36.56 cm3/cm3. The results of this paper support the multiphase fluid flow law prediction of CO2 flooding production wells with a high gas–liquid ratio.

Numerical simulation of non-isothermal supercritical water flow in ground pipeline and wellbore: An interactive sensitivity analysis and injection parameters optimization

Supercritical water injection is promising in enhanced heavy oil recovery, in which precise prediction and regulation of bottomhole parameters are the prerequisite for improving the recovery efficiency. However, dramatically changing thermophysical properties make it difficult to calculate the hydraulic and thermal resistances of supercritical water flow in ground pipeline and wellbore. In this work, a comprehensive mathematical model was established to simulate the non-isothermal flow of supercritical water from boiler outlet to bottomhole. Modified correlations of friction coefficients and convective heat transfer coefficients respectively developed for vertical and horizontal flow of supercritical water were coupled in momentum and energy conservation equations to calculate the hydraulic and thermal resistance. The model was validated by oilfield and laboratory data with the relative deviations of pressure and temperature less than 2%. The interactive sensitivity analysis was carried out by response surface method for injection parameters optimization. The results indicated that the heat loss in ground pipeline was comparable to that in wellbore once it reached 10 times longer than wellbore and should be taken into consideration. Increasing mass flux was found to be efficient for reducing the heat loss resulted from the decline of wellbore insulation. But there existed a matching combination of injection pressure and mass flux that making bottomhole temperature the highest. For a typical injection case with a poor insulation wellbore and limited injection temperature, a combination of high mass flux and low injection pressure was recommended for achieving targeted bottomhole temperature due to its high thermal efficiency.

Coupling Simulation of Longitudinal Vibration of Rod String and Multi-Phase Pipe Flow in Wellbore and Research on Downhole Energy Efficiency

The wellbore of a sucker–rod pumping well experiences a multi–phase flow consisting of oil, gas, and water. The flow pattern and pump discharge pressure are greatly impacted by oil well production, which in turn significantly affects the simulation results of longitudinal vibration in the sucker–rod string. When calculating the discharge pressure in a hydrostatic column containing both oil and water (HC), the pressure is not affected by the oil well’s production. This thereby avoids interference between vibrations in the sucker–rod string’s longitudinal direction and the flow from the wellbore. Considering the coupling characteristics between the longitudinal vibration of the sucker–rod string and the wellbore flow, a mathematical model of the sucker–rod pumping system (CMSRS) and a mathematical model of the downhole energy efficiency parameters were established. In detail, the CMSRS comprises two parts: the discharge pressure mathematical models of multi–phase flow dynamics (MD) and the wave equation of the longitudinal vibration of the sucker–rod string. A numerical simulation model of the sucker–rod pumping system was constructed based on a mathematical model. We compared the experimental results, the simulation results of the CMSRS and the simulation results of the sucker–rod string based on the oil–water two–phase hydrostatic column (SMSRS) and found good agreement, indicating the feasibility of the CMSRS. The simulation details show the following: (1) The HC model’s discharge pressure exceeds that of the MD model by more than 33.52%. The polished rod load for the CMSRS is 18.01% lower than that of the SMSRS, and the pump input power for the CMSRS is 36.23% lower than that of the SMSRS. (2) The effective power simulation model based on the energy balance relationship is essentially the same as the effective power calculated by the model based on multi–phase flow effective power. This validates the accuracy of the multi–phase flow effective power model. (3) The limitations of the industry standard effective power model are that (i) the effective head is the net lift height of the fluid in the wellbore reduced to the oil and water phases rather than the effective lift height based on the energy balance relationship and (ii) the power of the gas phase delivered by the pumping pump is disregarded, and only the effective power of the pump delivering the oil–water mixture is considered. (4) The influence of the wellbore parameters on the wellbore efficiency and sub–efficiency is systematically analyzed. The analysis results have an important significance in the guidance of energy saving in pumping wells.

Investigation on microscopic forces between methane hydrate particles in gas phase dominated system

Hydrate aggregation and deposition on the pipe wall are the main causes of hydrate plugging in pipelines. Microscopic forces between hydrate particles are an important reference for determining the behavior of aggregation or separation from the pipe wall of hydrate particles. Based on a high-pressure visual micro-force measurement system, this study measured the hydrate particle-hydrate particle cohesive force and hydrate particle–wall liquid droplet adhesion force under pure water, as well as hydrate particle–wall liquid droplet adhesion force under anti-agglomerants (AAs). It was found that the magnitude of hydrate particle-hydrate particle cohesive force was ×10 mN/m, and the magnitude of hydrate particle–wall liquid droplet adhesion force was ×103 mN/m. The effects of 4 AAs in the methane gas-dominated system were evaluated from a micro-perspective, revealing that after adding DDBAB, D1021, AEO-9, and CDEA, the maximum reduction of adhesion force was 67%, 64%, 51%, and 53% compared with that under pure water, respectively. The mechanism of AAs reducing adhesion force was further explored, revealing that the adhesion force arose from a liquid bridge and was affected by the gas–water interfacial tension of solutions at low subcoolings. While at high subcoolings, the force was determined by the combined force of the liquid bridge and the hydrate shell. The addition of AAs reduced the gas–water interfacial tension of solutions, and the steric hindrance effect of AA molecules also weakened the tensile strength of the hydrate shell, leading to a decreased adhesion force. These experimental data can help deepen our understanding of the microscopic forces between methane hydrate particles, and provide experimental data and scheme design basis for wellbore flow assurance of deepwater gas wells.

Improving production and prediction of the flow regimes, pressure drop, and void fraction in the perforated horizontal wellbore

This study aimed to investigate how oil production could be improved by experimenting with different distribution methods across multiple profiles. The authors tested five different profiles that included uniform radial airflow (explained in profile 1) and variable radial airflow (explained in profiles 2, 3, 4 and 5) in a perforated horizontal wellbore. In addition, the study predicted the behavior of total pressure drop, superficial mixture velocity and void fraction encountered in different flow patterns (bubble, slug, stratum and stratum wave flow). Flow patterns were predicted using ANSYS Fluent R3 with a borehole length of 3 m and an ID of 0.0381 m. This was designed with 12 perforations opening vertically at the wellbore with a phase angle of 180 and a perforation density of 4 shots per foot to simulate the complex flow in a horizontal wellbore. In the perforated section, there was a fluctuation in the behavior of the parameters, while in the non-perforated section, the behavior remained constant. The behavior of the total pressure drop, the superficial velocity mixtures and the void fraction were also reasonably uniform in profile 1 in the perforated section.In contrast, they were irregular in the other profiles. In profiles 2, 3, 4 and 5, the behavior of the mixture superficial velocity and void fraction was inverse to the total pressure drop. Note that all theoretically calculated pressure drop modes increased as the Reynolds number of the mixture increased. The liquid and air product increased with increasing Reynolds number of mixture flow in the profiles. In contrast, in profile 1, lower production was obtained through all flow patterns due to the influence of the mixture pressure and the friction factor. The Vogels method was used to calculate maximum production from the horizontal wellbore. The convergence between experimental and numerical results was good during all cases (flow patterns), with some difference in the static pressure drop behaviuor occurring during flow patterns (bubble, dispersed bubble and slug flow).

Engineered flowback and reservoir evaluation for unconventional wells

A flowback procedure is presented that uses a wellbore model coupled with thermal and fluid modelling to calculate the bottomhole pressure (BHP) and maximise the safe initial production/drawdown without over-stressing and damaging the fracture system. After obtaining the BHP, it is then possible to determine the fractured reservoir volume, fracture-dominated volume, and matrix contribution. The paper presents a case history validating the model calculations in an unconventional well. Two methods of decline analysis are presented, ‘Conventional’ and ‘Thermodynamic Transient Analysis’ (TTA), and together, these methods provide insights into the fracture system and overall reservoir volumes by recognising and applying the appropriate equation for the proper reservoir flow regime. The early flowback period can be used to determine the frac volume, while later periods will begin showing the increasing amount of matrix contribution. The wellbore flow model and decline analysis calculations are verified by a case history presented in the paper, where this flowback process was utilised on a hydraulically fractured East Texas well. The wellhead pressures (WHPs) in this case study highlight the need to accurately calculate BHPs based on the WHP and rates, due to significant differences between the trends and decline rates of the respective pressures.

An updated numerical model of fracture fluid loss coupled with wellbore flow in managed pressure drilling

The loss of drilling fluids often occurs during reservoir extraction in fractured formations, and the prediction of natural fracture loss rate is vital for controlling drilling fluids loss. However, the coupling of loss model to wellbore flow has rarely been considered. Based on the non-Newtonian fluid loss dynamics theory, this study considers Herschel–Buckley fluid and develops an updated numerical model to couple the loss of fracture with wellbore flow. The roughness of the fracture is characterized using the continuous random accumulation method. The coupling model is verified by field data, and its simulated results show the average relative and maximum relative errors were 4.76% and 12.8%, respectively. A linear throttle valve is introduced to simulate the effect of regulating wellhead back pressure and pump displacement on drilling fluids loss in managed pressure drilling, and the results indicate that the impact of regulating wellhead back pressure is better than that of pump displacement. This paper studies the pressure fluctuates of the fractured borehole breathing mechanism in detail and has proposed two possible scenarios that may cause borehole breathing. Increasing the wellhead back pressure can convert the overflow into loss, while reducing the wellhead back pressure by too much at once may also turn a loss into an overflow. The orthogonal experiment design is performed to study the influence of eight parameters on the loss rate, and the order of influence is as follows: fracture width, fluidity index, fracture area, consistency factor, yield stress, drilling fluids density, circulating displacement, and fracture dip.

Probabilistic forecasting of cumulative production of reservoir fluid with uncertain properties

Offshore development requires large investments, which have to be made in the presence of multiple sources of uncertainty. Quantification of uncertainty in predictions of a reservoir’s production and, consequently, the project’s revenue alleviates some of the risks and facilitates more informed business decisions. Despite significant advances in the field of uncertainty quantification, it is still common practice in the industry to rely on most likely parameters for the wellbore and pipeline multiphase flow models when making predictions for the project design. We focus on predictive uncertainty of pipe-flow models, which are used to forecast the cumulative production of an oil reservoir whose fluid properties are typically unknown during the exploration phase. The uncertain inputs of a flow model are treated as random variables with a multivariate Gaussian probability density; the model’s prediction of cumulative production is given in term of its distribution, which is estimated via Monte Carlo with Latin hypercube sampling. A global sensitivity analysis is performed to identify the model inputs contributing most to the predictive uncertainty.

CFD simulation of flow interference between multi-stage fractures along a horizontal wellbore

This paper investigates flow interference between multiple hydraulic fractures along a horizontal wellbore. The flow interference may cause large production rate losses and is a threat to reservoir asset management, but it has not received sufficient attention. Capable of simulating complex fluid flow phenomena with a high degree of accuracy, Computational fluid dynamics (CFD) simulation is employed to investigate the flow interference behavior of individual fracture streams and bulk flow in a horizontal wellbore with different fracture numbers and spacing and to provide insights into the relationship between fracture number, fracture spacing, flow velocity, pressure differential, and flow interference intensity. The results show that flow interference arises from competition for flow space between fracture streams. A longer horizontal wellbore and more hydraulic fractures can lead to higher bulk flow velocity and thus higher interference intensity. The interference intensity is found to be positively dependent on fracture number with a fixed fracture spacing. The velocity behaviors of individual fracture streams driven by declining pressure differential are also studied, showing a decline trend related to flow velocity. The intensity undergoes a mitigatory process before reaching a steady decline, and even flow interference at a lower intensity level still can lead to large production rate losses and profit reduction. The study suggests the need for countermeasures during well design and fracturing design to mitigate flow interference and reduce asset management risk.