Development of Next Generation Multiphase Pipe Flow Prediction Tools

A canned motor pump for technology demonstration in subsea oil and gas systems was tested to provide data to understand the design, modeling and performance characteristics of a canned motor pump operating in multiphase flow. This paper discusses the impact of multiphase flow and fluid viscosity on axial thrust and motor cooling flow characteristics. The technology demonstrator is a two-stage, low specific speed (Ns∼550) centrifugal pump designed to deliver 140 gpm at 600 feet of head at 3930 rpm. The 61 hp canned motor is cooled by a small portion of the pump discharge fluid, which is drawn downward through the motor by pump out vanes on the hub of the second stage impeller. The multiphase test loop is equipped for both water and light oil operation in low pressure and ambient temperature conditions. Testing occurred over a range of conditions to simulate varying fluid properties and operating scenarios. Shaft rotational speed varied between 2000 and 4250 rpm with pump liquid flow rates from 25 to 250 gpm. These operating scenarios were repeated for both water and light oil (∼2 cP) with multiphase flow ranging from 0–20% gas volume fraction (GVF) using injected air. Testing results indicate a detectable impact from the different fluids and GVF’s tested, which can be related to features such as the second stage impeller pump-out vane and regions within the motor cavities. In water-air tests, increasing GVF led to the following: motor input power reduced by 5%; axial thrust increased by 100%; motor cooling fluid temperature rise increased by 100%; and pressure rise in the second stage pump out vanes reduced by 30% - directly impacting motor cooling flow rate, temperature rise, and axial thrust. In the oil-air tests, multiphase flow showed similar tendencies with reduced magnitude. Notably, the effects due to air injection do not appear at GVF below 15% with oil-air mixtures, unlike water-air tests which demonstrated effects across all GVFs. The test results provide insight into the behavior of variable viscosity, multiphase flow in the canned motor pump cooling passages, as driven by the second stage impeller pump out vanes. These observed characteristics can be used to design flow control features and evaluate operational impacts, while the performance data obtained can be used to assess the behavior of flow models for this application.

Multiphase flow phenomena are widespread in nature and production process. The study of the flow mechanism and characteristics are a very important in the multiphase pipe flow. The establishment of multiphase flow experimental devices and systems is necessary in the study. In order to multi-phase pipe flow simulation, the small-scale physical experimental system based on the PLC control, and the experimental simulation system of based on Configuration software design are achieved. The physical experimental system can be achieved signals acquisition and control. Bubble flow, stratified flow, wavy flow, slug flow and other flow patterns can be formed in the experimental pipeline by changing the oil-gas-water flow rate. The virtual experimental system consists of the control interface and virtual physical interface. The simulation experiments of the multiphase flow generation can be achieved through the data exchange by two computers. This system meets the requirements for multiphase flow experiment.

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary. Multiphase flow can occur throughout the production system. Thefluids involved in multiphase flow in the petroleum industry are multicomponentmixtures with complex phase behavior. Petroleum engineers are faced with theneed to predict the relationships between flow rates, pressure drop, and piping(geometry or reservoir fluids produced during, the life of a field. This paperreviews the historical (Development of design tools used to address theseunique multiphase-flow features. State-of-the-art technology is alsopresented. Introduction Multiphase flow can occur throughout the entire production system involvedin flowing fluids from oil and gas reservoirs to processing facilities at thesurface. The production system in this context includes the reservoir: the wellcompletion: the tubulars that connect the reservoir to the surface: all surfacefacilities on land, seabed. or offshore platform and any pipelines that carryproduced fluids to other processing facilities. The multiphase flow encounteredin producing oil and gas can be any combination of a saturations phase, ahydrocarbon liquid phase, and a water phase. A vast amount of technical information on multiphase flow in pipes isavailable in the literature. Many of these sources are related to otherindustries and involve different types of- fluids. The reference list for thispaper clearly demonstrates the diversity of interest in multiphase flow inpipes. In particular, significant contributions have been made in the nuclearindustry. where a major concern is a possible loss-of--coolant accident in anuclear reactor. These studies involve the transient simulation of two-phase, single-component (water) fluid flow in piping systems. Multiphase flow in the petroleum industry has many unique features thatcreate complications not encountered by other industries. The fluids involvedare multicomponent mixtures whose phase behavior is extremely complex. Therange of pressures and temperatures encountered in production systems isextremely broad. Pressures can range from 15.000 psia [100 MPa] to nearatmospheric conditions. Temperatures can range from 400deg.F [200deg.C) to below the freezing, temperature of water. Pipe lengths can vary from a few feet to several hundredmiles for surface pipe or pipelines and from a few hundred feet to more than20,000 ft (6100) mi for wells. Piping, systems often involve significantvariations in (geometry, such as inclination angle. Diameter, pipe roughness, and even shape, such as when fluids flow in the annular space between casingand tubing in a wellbore. Although most vertical piping systems involve upflow, it is not uncommon to have multiphase downward flow in injection wells ordowncomers connecting, offshore platforms to subsea pipelines. Simulationmultiphase flow in wells also requires the ability to predict fluidtemperatures in a system that undergoes complex heat transfer phenomena betweenthe reservoir and the surface. The entire wellbore is surrounded by a huge rockvolume, much of which may even be frozen, as in the case of permafrost inarctic locations. Engineers in the petroleum industry are faced with the requirement topredict the relationships between flow rates, pressure drop, and pipinggeometry (length, diameter, angle, etc.) for the fluids produced from areservoir over the entire life of the field. The objective of this paper is toreview the historical development of design tools used to address the uniquemultiphase-flow features of the petroleum industry, including an evaluation ofthe state of the art. JPT P. 15^

The venturi meter has an advantage in its use, because it can measure flow without being much affected by the type of the measured fluid or flow conditions. Hence, it has excellent versatility and is being widely applied in many industries. The flow of a liquid containing air is a representative example of a multiphase flow and exhibits complex flow characteristics. In particular, the greater the gas volume fraction (GVF), the more inhomogeneous the flow becomes. As a result, using a venturi meter to measure the rate of a flow that has a high GVF generates an error. In this study, the cause of the error occurred in measuring the flow rate for the multiphase flow when using the venturi meter for analysis by CFD. To ensure the reliability of this study, the accuracy of the multiphase flow models for numerical analysis was verified through comparison between the calculated results of numerical analysis and the experimental data. As a result, the Grace model, which is a multiphase flow model established by an experiment with water and air, was confirmed to have the highest reliability. Finally, the characteristics of the internal flow field about the multiphase flow analysis result generated by applying the Grace model were analyzed to find the cause of the uncertainty occurring when measuring the flow rate of the multiphase flow using the venturi meter. A phase separation phenomenon occurred due to a density difference of water and air inside the venturi, and flow inhomogeneity happened according to the flow velocity difference of each phase. It was confirmed that this flow inhomogeneity increased as the GVF increased due to the uncertainty of the flow measurement.

Solid particle erosion is a major problem in many industrial applications where solids are entrained in gas and/or liquid flows. For example, erosion of production equipment, well tubing and fittings is a major operating problem that costs the petroleum industry millions of dollars each year. Entrained sand particles in the oil/gas production fluid impinge on the inner surfaces of the pipes, fittings, and valves that result in solid particle erosion. In certain production situations with corrosive fluids, erosion is compounded with corrosion causing severe erosion-corrosion. Even in situations when sand control means are utilized such as gravel packing and sand screens, small sand particles can plug sand screens promoting higher flow velocities through other portions of the screens causing failure and allowing sand production. Erosion can cause severe damage to the piping and equipment wall, resulting in loss of equipment and production downtime. Solid particle erosion is a mechanical process by which material is removed gradually from a solid surface due to repeated impingement of small solid particles on the metal surface. The erosion phenomenon is highly complicated due to the number of parameters affecting the erosion severity, such as production flow rate, sand rate, fluid properties, flow regime, sand properties, sand shape and size, wall material of equipment, and geometry of the equipment. For ductile materials, erosion is caused by localized deformation and cutting action from repeated particle impacts. It is well known that solid particle erosion rates are a strong function of the impacting velocity of particles and also the mass of impacting particles. Predicting solid particle erosion in multiphase flow is a complex task due to existence of different flow patterns. The existence of different flow patterns and sand and liquid holdup in vertical and horizontal pipes means that a unique erosion model has to be developed for each flow regime if the model is to account for the number and velocity of impacting particles. The particle impact velocity is affected by the pipe geometry, carrying fluid properties and velocity, flow pattern, particle size and distribution in the flow. Among different multiphase flow patterns in horizontal and vertical flows, severe erosion damage can occur in annular and slug flows with high gas velocities and low liquid velocities. Although there is a lack of accurate mechanistic models to predict solid particle erosion, there is a need to develop engineering prediction models for multiphase flows. Earlier erosion calculation procedures in multiphase flow were primarily based on empirical data and the accuracy of those “empirical” models was limited to the flow conditions of the experiments. A framework for developing a model has been established for predicting erosion rates of elbows in multiphase flow. The model considers the effects of particle velocities in gas and liquid phases upstream of the elbow. Local fluid velocities in multiphase flow are used to determine representative particle impact velocities. Also based on data representing sand holdup for several flow regimes, the masses of impacting particles are estimated. Erosion experiments are also conducted on elbows in two-inch and three-inch large scale multiphase flow loops with gas, liquid and sand flowing in vertical and horizontal test sections. Based on the experimental data for different flow regimes including slug, wet gas and annular flow a method for improving a previous model is discussed and is being implemented to predict erosion rates in multiphase flow.

An experimental study on gas/liquid/solid three-phase flow in horizontal coalbed methane production wells

Previous multiphase pipe flow tests have mainly been conducted in horizontal and vertical pipes, with few tests conducted on multiphase pipe flow under different inclined angles. In this study, in light of mid–high yield and highly deviated wells in the Middle East and on the basis of existent multiphase flow pressure research on well bores, multiphase pipe flow tests were conducted under different inclined angles, liquid rates, and gas rates. A pressure prediction model based on Mukherjee model, but with new coefficients and higher accuracy for well bores in the study block, was obtained. It was verified that the newly built pressure drawdown prediction model tallies better with experimental data, with an error of only 11.3%. The effect of inclination, output, and gas rate on the flow pattern, liquid holdup, and friction in the course of multiphase flow were analyzed comprehensively, and six kinds of classical flow regime maps were verified with this model. The results showed that for annular and slug flow, the Mukherjee flow pattern map had a higher accuracy of 100% and 80–100%, respectively. For transition flow, Duns and Ros flow pattern map had a higher accuracy of 46–66%.

Conventional multiphase pump technologies typically handle intake gas volume fractions (GVFs) of 75%. Recent work has shown development of an Ultra-High-Speed High GVF Pump (UHS HGVFP) with significant boost pressure at 90% intake GVF. The current work discusses the physical performance test results of a tandem UHS HGVFP and showcases pump behavior with increased number of modules. Knowledge from such work is beneficial in multiphase pump sizing for production in high gas-oil ratio wells. A 4 in. housing outer diameter, tandem (double module) UHS HGVFP was tested at a rotational speed of 10,000 rev/min. Air and water were the working fluids, and liquid volume flow rates varied from about 550 to 1980 barrels per day (B/D). The gas flow rates were adjusted accordingly to achieve a 0% to 90% intake GVF range. For each test data, pressures and temperatures at pump intake and pump discharge and gas lines were measured, with corresponding pump boost pressures computed. Pump performance was plotted and results compared with those of a single-module UHS HGVFP at same GVFs. The results showed a steady decrease in boost pressure as the intake GVF varied from 0% (liquid-only tests) to 90%. For the same boost pressures, the magnitudes of liquid volume flow rate delivered by the pump decreased with increasing intake GVF and vice versa. The tandem UHS HGVFP test results were compared to those of a previously tested single-module UHS HGVFP when pumping only water. For the same liquid volume flow rates and intake pressures, the boost pressure from the tandem-module was, on average, about two (2) times those of the single-module UHS HGVFP. This indicates that for liquid only tests, doubling the number of stages also doubles the pump boost pressure. For intake GVFs from 15% to 90%, the tandem UHS HGVFP produced about 1.24 to 1.88 times the boost pressure of a single-module UHS HGVFP. Lower boost pressure ratios were observed as intake GVF approached 90%. These results indicate that at higher intake GVFs, doubling the number of modules does not double the boost pressure boost capability of the pump. Knowledge gained from these tests are vital for successful multiphase performance sizing of the UHS HGVFP ahead of field installation and trial. At low intake GVFs, a tandem (2-module) UHS HGVFP can produce double the pressure boost of a single-module UHS HGVFP, but is not the case at higher intake GVFs up to 90%. Knowledge of such performance trends are crucial for proper sizing of the UHS HGVFP. Results from this study indicate that a series of multiple-module UHS HGVFP has superior capabilities to handle multiphase flows in wells with high gas-oil-ratios.

With the ongoing increase in global energy demand, the significance of innovations in oil exploration and development technologies is rising, especially in relation to the development of unconventional reservoirs. The application of horizontal wells is becoming increasingly important in this particular situation. However, accurately monitoring and analyzing fluids in horizontal wells remains challenging due to the complex and fluctuating flow patterns of oil-water two-phase flow within the wellbore. Several elements, including well slope angle, flow rate, and water content, are involved. This study aimed to explore and develop an effective method for forecasting flow patterns, improving the precision of the dynamic monitoring of oil-water two-phase flow in horizontal wells. By analyzing the flow patterns in different experimental conditions, a predictive model using the SOA-BP neural network was developed, providing a scientific basis for dynamic monitoring in actual production scenarios. Initially, the simulated experiment for oil-water two-phase flow was carried out at room temperature and pressure utilizing a multiphase flow simulator. An optically transparent wellbore, with a diameter comparable to that of a real downhole well, was utilized, and No. 10 industrial white oil and tap water were employed as the experimental fluids. The experiment considered multiple contributing factors, including different well deviation, total flow, and water cut. The flow characteristics of oil and water were observed via visual monitoring and high-definition video, followed by detailed analysis. After collecting the experimental data, flow regimes for various scenarios were classified based on the established theory of oil-water two-phase flow in horizontal wells; then, detailed flow distribution diagrams were drawn. These data and diagrams presented offer a visual representation of the behavioral patterns exhibited by oil-water two-phase flow under varying situations and form the basis for subsequent model training and testing. Subsequently, based on the experimental data, this study combined the Seagull Optimization Algorithm (SOA) with a BP neural network to effectively learn and predict the experimental data. The SOA optimized the weights and biases of the BP neural network, improving the model’s convergence speed and prediction accuracy. Through rigorous training and testing, an oil-water two-phase flow pattern forecasting model was established, effectively predicting flow patterns under different well deviation, total flow, and water cut conditions. Finally, to validate the efficiency of the established model, a total of 15 data points were chosen from a sample well for validation. By comparing the flow patterns predicted by the model with actual logging data, the results indicate that the model’s accuracy in identifying flow pattern was 86.67%. This demonstrates that the flow pattern prediction model based on the SOA-BP neural network achieved a high level of accuracy under different complicated working conditions. This model effectively fulfills the requirements for dynamic monitoring in actual production. This indicates that the SOA-BP neural network-based flow pattern forecasting method is highly valuable due to its practical application value and provides an efficient technical approach for the development of unconventional reservoirs and the dynamic monitoring of horizontal wells in the future.

Accurate predictions of flow patterns for multiphase flow in pipes remain unresolved problems in petroleum engineering. Many efforts have been directed towards improved understanding of the phenomena and the development of physical models that allow more accurate analytical predictions of the flow pattern transition boundaries in steady-state multiphase flow. The primary goal of such models is to provide a truly general method that predicts existing flow patterns, once the flow rates, pipe geometry, and the fluid properties are specified. A unified approach, in which the same transition mechanisms can be applied over the whole range of inclination angle, has also been proposed. The most essential part of solving engineering problems that depend on flow pattern predictions is the interpretation of results. The ability to explore and manipulate the results using a computerized flow pattern simulator would greatly enhance an engineer’s capability to optimize the design of multiphase transportation systems. This would also permit eliminating undesirable operating conditions; e.g. severe slugging at the riser in offshore operations. Progress in the area of Artificial Intelligence (AI) has made possible the partial realization of human decision making ability in a computer program. An intelligent program, supported by a knowledge data base, an inference engine, and human interaction, is an effective and economical solution for the present needs of advanced production optimization. A computer simulator is undergoing development, using a Knowledge Based System approach. The system attempts to imitate, and eventually replace, a multiphase flow engineering expert. The Expert System utilizes an inference engine which is based on analytical mechanistic models and the expertise of many multiphase flow engineering experts and consultants. It is capable of predicting the existing flow pattern based on the current design, and will offer advice on alternatives and the direction to proceed if the existing flow pattern is unacceptable, or potentially problematic.

Development of numerical Eulerian-Eulerian models for simulating multiphase pumps

Multiphase flow in a microchannel is the basis for the application of microchemical process and flow chemistry. The gas-liquid two-phase flow, liquid-liquid two-phase flow, and gas-liquid-solid three-phase flow in a microchannel are introduced. Due to the interplay of the interfacial phenomena and the confinement effect at microscale, various flow patterns of the multiphase flow in a microchannel occur, such as Taylor bubble flow, bubbly flow, churn flow, parallel flow, and annular flow for gas-liquid two-phase flow (tiny droplet, plug droplet, annular flow, and parallel flow for liquid-liquid two-phase flow). Bubbles and droplets are the typical flow patterns for multiphase flow in a microchannel. The mechanism and manipulation for the generation, breakup, and coalescence of bubbles and droplets in a microchannel are highlighted. The interface evolution for the bubble dynamics and droplet dynamics in a microchannel is reported, to shed light on the interfacial instability mechanism. Bubbles or droplets can be generated in a microchannel via the dripping, jetting, squeezing, or tip-streaming, by various forces exerted on the gas-liquid interface or liquid-liquid interface such as interface tension force, viscous force, and inertia. Various breakup mode and coalescence mode for bubbles and droplets in a microchannel are observed. The interfacial mass transfer across the gas-liquid interface via a bubble and the liquid-liquid interface via a droplet is analyzed. Due to the increased specific surface area, the related mass transfer process can be intensified. Multiphase flows involving particles are also presented such as for particle separation and nanomaterials synthesis.

Onshore gas developments are often characterized by drilling, fracturing and production of wells before low-pressure gas gathering systems are in place. As well production declines, liquid loading issues begin to appear. Gas well deliquification (GWD) can be accomplished using compression or in-well artificial lift methods, or both. Wellhead wet-gas compression is desirable in that it does not require well intervention to provide GWD and is especially useful to maintain well production in the interim period before field-wide compression is available. Also, even when field-wide compression is available local wellhead compression is desirable at various locations in a field as high-rate wells are added or for wells located at peripheral locations. The use of a twin-screw pump to provide boost for high Gas Volume Fraction (GVF) multiphase flow was experimentally investigated. Tests were conducted with pressure rises ranging up to 250 psi for GVF's above 90%. Water and air were used as the working fluid. The pumping system is a commercially available 230 gpm twin-screw pump (60 hp) with a design speed of 3600 rpm used in conjunction with a knock out tank used to re-circulate liquid from the pump exit to provide seal flush. The electrical power required to operate the pump, liquid and gas inlet flow rates, pressure rise, and inlet and exit temperatures were recorded. From these data, the volumetric efficiency, pump effectiveness, and mechanical efficiency were calculated. Since there is a fixed clearance between the rotating screws and the pump housing, there is a leakage from the high to low pressure regions of the pump which will reduce the pump's volumetric efficiency. It was found that the volumetric efficiency decreased significantly with decreasing pump speed and decreasing GVF. At full speed the volumetric efficiency was between 70 and 88% at DP=50 psi. Increasing DP to 250 psi decreased these values to 55 and 81% respectively. The mechanical efficiency was relatively constant over the pressure rise range varying from a high of 48% at the lowest inlet pressure and 100% GVF to a low of 14% 14% for both inlet pressures at 100% GVF. Overall, the testing demonstrated the ability of a surface twin-screw pump to provide wet-gas compression and to tolerate 100% gas input, which may results from slugging or periodic flow, for relatively large periods of time.

An oil-water flow pattern classification and characterization for wellbores is proposed based on the integrated analysis of experimental data, including frictional pressure drop, holdup and spatial phase distribution, acquired in a transparent test section (2 in. ID, 51 ft long) using a refined mineral oil and water (=0.85, =20.0 and =33.5 dyne/cm at 90 F). The tests covered inclination angles of 90, 75, 60 and 45 from horizontal. The oil-water flow patterns have been classified into two major categories given by the status of the continuous phase, including water dominated flow patterns and oil dominated flow patterns. It was found that most water dominated flow patterns show significant slippage but relatively low frictional pressure gradients. In contrast, all the oil dominated flow patterns exhibit negligible slippage but significantly larger frictional pressure gradients. Six flow patterns have been characterized in upward vertical flow; three were water dominated and three were oil dominated. In upward inclined flow there were four water dominated flow patterns, two oil dominated flow patterns and a transitional flow pattern. Flow pattern maps for each of the tested inclination angles are presented. A mechanistic model to predict flow pattern transitions in vertical wells is proposed. The transitions to the very fine dispersed flow patterns were evaluated by combining the concepts of turbulent kinetic energy with the surface free energy of the droplets, while the transitions to the churn flow pattern and the phase inversion were predicted based on the concept of agglomeration. The model compares favorably with the measured data. Introduction Two-phase flow of oil and water is commonly encountered in wellbores; however, its hydrodynamic behavior under a wide range of flow conditions and inclination angles constitutes a relevant unresolved issue for the oil industry. Multiphase flows are characterized by the existence of diverse flow configurations or flow patterns, which can usually be identified by a typical geometrical arrangement of the phases in the pipe. Inherent to each flow pattern are characteristic spatial distributions of the interface, flow mechanisms and distinctive values for design parameters such as pressure gradient, holdup and heat transfer coefficient. There is clear evidence that accurate knowledge of oil-water flow patterns, their ranges of existence as a function of flow rates and pipe inclination angles, and values for their associated hydrodynamic parameters are crucial in a number of production engineering applications. These include production optimization, optimum string selection, production logging interpretation, -downhole metering and artificial lift design and modeling. Additionally, the understanding of oil-water flow in wellbores is fundamental in determining the volumes of free water in contact with the pipe that could cause scaling and corrosion of the pipe after prolonged exposure. This paper addresses the fundamental problem of identifying and characterizing oil-water flow patterns and predicting flow pattern transitions for conditions pertinent to oil-water producing wells. Literature Review Despite being a subject of permanent interest for the petroleum industry, the issue of oil-water flow patterns in wellbores has barely been addressed in the technical literature. A limited number of experimental studies have been found that provide a description of the flow patterns for low-medium viscosity oil and water. Govier et al. and Zavareh et al. conducted investigations in vertical flow, while Scott and Zavareh et al. covered inclinations near the horizontal and near the vertical, respectively. A larger number of related studies concentrated on measuring the holdup, mainly for oil dispersed systems, focusing on finding expressions for the slip velocity that could be used in the interpretation of production logs. P. 601^

Carbon Capture and Storage (CCS) is a promising technology that stops the release of CO2 from industrial processes such as electrical power generation. Accurate measurement of CO2 flows in a CCS system where CO2 flow is a gas, liquid, or gas-liquid two-phase mixture is essential for the fiscal purpose and potential leakage detection. This paper presents a novel method based on Coriolis mass flowmeters in conjunction with least squares support vector machine (LSSVM) models to measure gas-liquid two-phase CO2 flow under CCS conditions. The method uses a classifier to identify the flow pattern and individual LSSVM models for the metering of CO2 mass flowrate and prediction of gas volume fraction of CO2, respectively. Experimental work was undertaken on a multiphase CO2 flow test facility. Performance comparisons between the general LSSVM and flow pattern based LSSVM models are conducted. Results demonstrate that Coriolis mass flowmeters with the LSSVM model incorporating flow pattern identification algorithms perform significantly better than those using the general LSSVM model. The mass flowrate measurement of gas-liquid CO2 is found to yield errors less than ±2% on the horizontal pipeline and ±1.5% on the vertical pipeline, respectively, over flowrates from 250kg/h to 3200kg/h. The error in the estimation of CO2 gas volume fraction is within ±10% over the same range of flow rates.