Visualization and Analysis of the Multiphase Flow in an Electromagnetically Driven Dosing Pump

Modern hydraulic systems are operating at higher pressures and higher temperatures than ever before. In addition, the life and reliability of the hydraulic components and hence the hydraulic system is becoming more and more dependent upon the characteristics of the circulating fluid in the system. The hydraulic component which normally suffers most when the correct fluid is not used in the system is the hydraulic pump. Three different types of hydraulic pumps are widely used in hydraulic systems. Vane pumps have been the dominant type of pump for hydraulic systems. Gear pumps have replaced vane pumps in many applications. Piston pumps are rapidly gaining popularity. Therefore, the pump manufacturers are conducting tests to qualify fluids for use with their pumps and the fluids formulators are conducting tests to show that their formulations are compatible with hydraulic components. Unfortunately, the tests most widely used are either not industry standards or do not address problems encountered with some hydraulic pumps. This paper presents an overview of the pump tests which are currently available or which are specific to certain hydraulic pumps. Since there are few standard pump tests, many companies have devised their own tests to be confident of the fluids which they qualify. Additional concepts in pump testing are proposed and discussed.

The effects of various intravenous delivery systems on the integrity of infused red blood cells (RBCs) were studied. Using a factorial design, whole blood and packed RBCs were infused through i.v. delivery systems employing various combinations of i.v. tubing diameter and length, needle gauge, infusion rate (5 and 50 ml/hr), type of infusion pump (piston, diaphragm, or peristaltic operation), and type of blood product. The age and temperature of the blood filter used were held constant. A 5-ml sample of the blood product obtained during each experimental run was analyzed for plasma free-hemoglobin to assess the degree of hemolysis. Osmotic fragility of the RBCs was evaluated by measuring the percentage of hemolysis in the blood products in various concentrations of sodium chloride solution. Type of blood product and i.v. pump were the only variables significantly influencing RBC hemolysis. In both blood products, a greater degree of hemolysis occurred with the peristaltic-type pump than with the other types of pumps. In packed RBCs, the diaphragm-type pump produced greater hemolysis than the piston-type pump, but hemolysis was similar in whole-blood samples. Regardless of the type of pump, more hemolysis occurred in whole blood at the 5-ml/hr infusion rate than at the 50-ml/hr rate, but the converse was true in packed RBCs. Samples of both blood products were less osmotically fragile than their respective controls at sodium chloride concentrations ranging from 0.30 to 0.50%.(ABSTRACT TRUNCATED AT 250 WORDS)

SummaryCarbonate fractured reservoirs introduce a tremendous challenge to the upscaling of both single- and multiphase flow. The complexity comes from both heterogeneous matrix and fracture systems in which the separation of scales is very difficult. The mathematical upscaling techniques, derived from representative elementary volume (REV), must therefore be replaced by a more realistic geology-based approach. In the case of multiphase flow, an evaluation of the main forces acting during oil recovery must also be performed.A matrix-sector model from a highly heterogeneous carbonate reservoir is linked to different fracture realizations in dual-continuum simulations. An integrated iterative workflow between the geology-based static modeling and the dynamic simulations is used to investigate the effect of fracture heterogeneity on multiphase fluid flow. Heterogeneities at various scales (i.e., diffuse fractures and subseismic faults) are considered. The diffuse-fracture model is built on the basis of facies and porosity from the matrix model together with core data, image-log data, and data from outcrop-analogs. Because of poor seismic data, the subseismic-fault model is mainly conceptual and is based on the analysis of outcrop-analog data. Fluid-flow simulations are run for both single-phase and multiphase flow and gas and water injections.A better understanding of fractured-reservoirs behavior is achieved by incorporating realistic fracture heterogeneity into the geological model and analyzing the dynamic impact of fractures at various scales. In the case of diffuse fractures, the heterogeneity effect can be captured in the upscaled model. The subseismic faults, however, must be explicitly represented, unless the sigma (shape) factor is included in the upscaling process. A local grid-refinement approach is applied to demonstrate explicit fractures in large-scale simulation grids. This study provides guidelines on how to effectively scale up a heterogeneous fracture model and still capture the heterogeneous flow behavior.

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 developments of oil and gas fields in deep waters (5000 ft and more) will become more common in the future. It is inevitable that production systems will operate under multiphase flow conditions (simultaneous flow of gas, oil and water possibly along with sand, hydrates, and waxes). Multiphase flow prediction tools are essential for every phase of hydrocarbon recovery from design to operation. Recovery from deep-waters poses special challenges and requires accurate multiphase flow predictive tools for several applications, including the design and diagnostics of the production systems, separation of phases in horizontal wells, and multiphase separation (topside, seabed or bottom-hole). It is crucial for any multiphase separation technique, either at topside, seabed or bottom-hole, to know inlet conditions such as flow rates, flow patterns, and volume fractions of gas, oil and water coming into the separation devices. Therefore, the development of a new generation of multiphase flow predictive tools is needed. The overall objective of the proposed study is to develop a unified model for gas-oil-water three-phase flow in wells, flow lines, and pipelines to predict flow characteristics such as flow patterns, phase distributions, and pressure gradient encountered during petroleum production at different flow conditions (pipe diameter and inclination, more » fluid properties and flow rates). In the current multiphase modeling approach, flow pattern and flow behavior (pressure gradient and phase fractions) prediction modeling are separated. Thus, different models based on different physics are employed, causing inaccuracies and discontinuities. Moreover, oil and water are treated as a pseudo single phase, ignoring the distinct characteristics of both oil and water, and often resulting in inaccurate design that leads to operational problems. In this study, a new model is being developed through a theoretical and experimental study employing a revolutionary approach. The basic continuity and momentum equations is established for each phase, and used for both flow pattern and flow behavior predictions. The required closure relationships are being developed, and will be verified with experimental results. Gas-oil-water experimental studies are currently underway for the horizontal pipes. Industry-driven consortia provide a cost-efficient vehicle for developing, transferring, and deploying new technologies into the private sector. The Tulsa University Fluid Flow Projects (TUFFP) is one of the earliest cooperative industry-university research consortia. TUFFP's mission is to conduct basic and applied multiphase flow research addressing the current and future needs of hydrocarbon production and transportation. TUFFP participants and The University of Tulsa are supporting this study through 55% cost sharing. « less

The fluid borne noise characteristics of hydraulic pumps and motors are commonly represented in the frequency domain using a source flow ripple spectrum in parallel with a source impedance spectrum. This is equivalent to Norton’s theorem for electrical sources in which the source is represented as a current source in parallel with a resistance or impedance. The validity of this representation is considered for two types of piston pump through simulation and for a third piston pump through experiment. It is shown that the Norton model of source flow ripple and source impedance is a reasonable approximation to the fluid-borne noise characteristics of positive displacement pumps. However for pumps in which fluid compression is a dominant feature in the source flow ripple, such as piston pumps, the source flow ripple varies somewhat with the system pressure ripple, and this causes significant problems with the Two Loads method, resulting in unrealistic source impedance measurements.

A centrifugal pump is one type of pumps that widely used in industries. Its mechanism which creates pressure changes may cause cavitation. Cavitation phenomenon that is not properly maintained may results fatal breakdown leading to high economic losses. Therefore, research is needed to find and develop a method that can detect early cavitation phenomena and identify it at several levels as well. This paper presents a method that can detect cavitation by monitoring the vibrations level of the pump based on statistical analysis of time domain and Principal Component Analysis (PCA). Vibration data is collected, trained and tested for each cavitation level. Training data is normalized and trained for each cavitation level using PCA which produces data loading matrix. The loading matrix is then multiplied by the testing data which gives a score matrix used to classify cavitation level of the centrifugal pump. The result shows that the method of domain-based PCA is successful in transforming the original data of 7 statistical parameters to 7 principal components (PC) with maximum variant. Three PCs gives 93.68% variants which can clearly identify and classify the differences between normal, early, intermediate and fully developed cavitation in the centrifugal pumps.

The primary task of rotary shaft seals is to prevent an unwanted fluid transfer between two areas. In shaft passages of gearboxes, for example, rotary shaft seals avoid the leakage of transmission oil to ambient air. This means the flow in the lubricant film in the sealing gap between the sealing edge and the shaft surface consists of at least two phases. Taking the phenomenon of cavitation into account, the flow consists of three phases. This study aims to provide an in-depth understanding of the multiphase flow in the lubricant film of rotary shaft seals. As experimental studies of the flow processes on a microscale have proven to be quite difficult, a simulation-based approach is applied. Computational fluid dynamics (CFD) serves to compute the transient multiphase flows in the lubricant film in the sealing gap. The computational domain is a three-dimensional microscale model of the lubricant film. The results show the transient hydrodynamic pressure buildup and the dynamic phase interactions during operation. This study provides far-reaching insights into the multiphase flow processes in the lubricant film in the sealing gap and simulation-based evidence of the lubrication and sealing mechanism of rotary shaft seals.

In this research study, we conducted a coupled thermalstress-fluid flow numerical modeling on the UTF Phase A SAGD project in order to investigate the fundamental geomechanical behavior involved in the SAGD process and to gain insight into the reservoir response to temperature and pore pressure changes. The numerical simulation is carried out using a self-developed coupled finite element model which incorporates our proposed strain-induced permeability model. The obtained simulation results were compared with the measured data. Introduction Thermal recovery processes involve coupling between heat transfer, multiphase flow and stress/deformation, which has become an increasingly important subject in the petroleum field(1). Particularly, the coupling is crucial in problems such as borehole stability, hydraulic fracturing and injection/production induced deformation of the ground surface during the thermal recovery processes in the heavy oil or oil sand reservoirs. Numerical modeling of the coupled processes is historically carried out in the areas of geomechanics modeling and the reservoir simulation. The former is to compute the stress-strain behavior, therefore the deformation; the latter is to essentially model the multiphase flow and heat transfer in porous media. Each of these disciplines simplifies the part of the problem that is not of primary interest. These approaches are unacceptable in situations where the coupling is strong and the changes of porosity and permeability cannot be accounted by rock compressibility alone. Gutierrez and Lewis(2) extend Biot's theory to multiphase fluid flow in deformable porous media. Based on their formulation, they conclude that the coupling between the geomechanics and the multiphase flow occurs simultaneously. Thus, fully coupled system equations of deformations, multiphase flow and heat transfer should be solved simultaneously. Development of such kinds of fully coupled geomechanics-multiphase flow-heat transfer simulators needs tremendous effort, since the existing FEM geomechanics codes and the FDM reservoir simulators cannot be used. Settari and Mourits(3) present an approach to couple the stress-strain behavior to multiphase flow, heat transfer using porosity as a coupling parameter. The geomechanics module and the thermal reservoir simulator are used in a staggered manner. Pore pressure and temperature changes are calculated from the thermal reservoir simulator and transferred to the geomechanics module. The stress and the displacement changes are then calculated in the geomechanics simulation. An iterative algorithm is used to ensure that the porosity calculated from the geomechanics module is the same as that from the thermal reservoir simulator. The staggered technique employed to solve the coupled system equations allows for the use of the existing geomechanics codes in conjunction with a standard reservoir simulator. Currently, most of the commercial coupled geomechanics-multiphase flow-heat transfer simulators are developed in this way. The disadvantage of these kinds of coupled simulators is that the thermal reservoir module, usually developed using finite difference method (FDM), cannot accommodate the full permeability tensor, since they adopt the standard discretization scheme such as 5-spot for 2-D problems and 7-spot for 3-D problems. In this paper, the development of a coupled geomechanicsmultiphase flow-heat transfer simulator using finite element method (FEM) is described with the use of the Galerkin's least squares (GLS) technique(4) to stabilized the saturation equation.

Ventricular assist devices have been used for the treatment of severe heart failure. Recently, many types of blood pumps have been developed to reduce major adverse events. EVAHEART® (Sun Medical Technology Research Corporation, Nagano, Japan) is an implantable centrifugal blood pump. In laboratory animal studies, the pump flow of EVAHEART® increases spontaneously during exercise with no changes in pump control parameters. However, this has not been confirmed clinically. The aim of this study was to analyze EVAHEART® performance during exercise. Four male patients were implanted with an EVAHEART®. We evaluated the performance of the EVAHEART® during exercise. Fixed pump speeds were maintained during each test. Measurements during exercise were peak load, peak oxygen consumption (peak VO(2)), pre exercise pump flow, and peak velocity. Pump flow significantly increased from 4.1 ± 0.5 liters per minute (L/min) to 7.2 ± 1.8 L/min during exercise. VO(2) increased from 4.0 ± 0.7 milliliters per kilogram per minute (ml/kg/min) to 14.7 ± 3.3 ml/kg/min. These results indicate that EVAHEART® may support severe heart failure patients not only under static but also under dynamic conditions. Pump flow spontaneously increased during exercise at a constant pump speed.

Thermal Water Pumps on the Basis of Fluid Piston Solar Stirling Engine

Summary Cold heavy oil production with sand (CHOPS) technique has successfully improved oil recovery from heavy oil reservoirs due to high permeability channels resulted from sand failure and foamy oil flow enhancing heavy oil movability. However, impacts of the sand failure and the foamy oil flow on multiphase fluid flow features are still not properly understood. In this paper, an effective and systematic framework has been proposed to characterize the multiphase fluid flow and determine the three-phase relative permeability of CHOPS processes. A recently developed sand failure criterion and a relative permeability model have been integrated with a reservoir simulator to simulate the CHOPS process. The unknown parameters involved in the systematic framework are intelligently determined by an iterative ensemble smoother (IES) algorithm, which also enables sensitivity analysis on CHOPS production profiles. Subsequently, the proposed framework is tested through a laboratory CHOPS experiment. We obtained not only fairly history-matched production data (i.e., cumulative oil, gas, and sand production), but also satisfactorily converged three-phase relative permeability curves by iteratively assimilating production profiles of the CHOPS experiment. It has also been found that using two sets of three-phase relative permeability is capable of representing the segment-type nature of the multiphase flow and reproducing the transition stage on the production profiles. Furthermore, the comparison between two sets of three-phase relative permeability indicates that the sand failure phenomenon yields a reduced residual oil saturation and an increased oil/gas relative permeability. In addition, the sensitivity analysis demonstrates that the segment-type nature of production profiles results from the variation of key impact factors dominating the multiphase fluid flow in CHOPS processes. Overall, the proposed systematic framework can not only reproduce the physical phenomena of sand failure and foamy oil, but also provide a convenient tool to characterize the multiphase flow in CHOPS processes.

The focus of the underlying research work is on the macroscopic modeling of unstable multiphase fluid flow in deformable porous media, where a lower‐viscous fluid is displaced by a more viscous fluid. This process leads to the formation of channel‐like networks, called viscous fingering. The instability effect is involved in a wide range of different fields in engineering. Some of the most common applications include carbon sequestration to store carbon dioxide (CO2) in underground reservoirs, contaminant transport in geostructures, in industrial processes, such as filtration, catalytic reactions, and in the operation of polymer electrolyte membrane fuel cells with multiphase flow in the gas diffusion layers. In this work, ideal miscible water–glycerin fluids are considered. It is assumed that the interacting fluids in the deformable porous media are incompressible. In addition, a dispersion–diffusion law is applied to capture the fluid–fluid interactions. The presence of a deformable porous material adds additional effects to the problem of the multiphase flow in porous media. The stresses in the porous solid matrix lead to changes in the porosity and influence the flow velocity of the fluids. To couple the deformable porous media with the multiphase flow, a macroscopic approach is used that relies on the theory of porous media. For the porous solid matrix, a linear elastic material model within small strains assumption is applied. The influence of the deformation‐dependent porosity on the instability is studied for 2D simulations, such as a multilayered geometry with different elastic parameters. The presented coupled nonlinear system of differential equations is simulated with the finite element method. Furthermore, a stabilization technique based on the quasi‐compressibility method is used.

A 6M digital twin for modeling and simulation in subsurface reservoirs

In this research study, we conducted a coupled thermal-stress-fluid flow numerical model on the UTF Phase A SAGD project in order to investigate the fundamental geomechanical behaviour involved in the SAGD process, and to gain insight into the reservoir response to temperature and pore pressure changes. The numerical simulation is carried out by using a self-developed coupled finite element model which incorporates our proposed strain-induced permeability model. The obtained simulation results were compared with the measured data. Introduction Thermal recovery processes involve coupling between heat transfer, multiphase flow and stress/deformation, which has become an increasingly important subject in the petroleum field(1). Particularly, the coupling is crucial in problems such as borehole stability, hydraulic fracturing and injection/production induced deformation of the ground surface during the thermal recovery process in heavy oil or oil sand reservoirs. Numerical modelling of the coupled processes is historically carried out in the areas of geomechanics modelling and reservoir simulation. The former is to compute the stress-strain behaviour; therefore, the deformation. The latter is to essentially model the multiphase flow and heat transfer in porous media. Each of these disciplines simplifies the part of the problem that is not of primary interest. These approaches are unacceptable in situations where the coupling is strong and the changes of porosity and permeability cannot be accounted for by rock compressibility alone. Gutierrez and Lewis(2) extend Biot's theory to multiphase fluid flow in deformable porous media. Based on their formulation, they conclude that the coupling between the geomechanics and the multiphase flow occurs simultaneously. Thus, fully coupled system equations of deformations, multiphase flow and heat transfer should be solved simultaneously. Development of such kinds of fully coupled geomechanics-multiphase flow-heat transfer simulators needs tremendous effort, since the existing FEM geomechanics codes and FDM reservoir simulators cannot be used. Settari and Mourits(3) present an approach to couple the stress-strain behaviour to multiphase flow-heat transfer using porosity as a coupling parameter. The geomechanics module and the thermal reservoir simulator are used in a staggered manner. Pore pressure and temperature changes are calculated from the thermal reservoir simulator and transferred to the geomechanics module. The stress and the displacement changes are then calculated in the geomechanics simulation. An iterative algorithm is used to ensure that the porosity calculated from the geomechanics module is the same as that from the thermal reservoir simulator. The staggered technique employed to solve the coupled system equations allows for the use of the existing geomechanics codes in conjunction with a standard reservoir simulator. Currently, most of the commercial coupled geomechanics-multiphase flow-heat transfer simulators are developed in this way. The disadvantage of these kinds of coupled simulators is that the thermal reservoir module, usually developed using the finite difference method (FDM), cannot accommodate the full permeability tensor, since they adopt the standard discretization scheme, such as 5-spot for 2D problems and 7-spot for 3D problems. In this paper, the development of a coupled geomechanics-multiphase flow-heat transfer simulator using the finite element method (FEM) is described with the use of Galerkin's least squares (GLS) technique(4) to stabilize the saturation equation.