Gas-liquid flow in inclined pipes was investigated to determine the erect of pipe inclination angle on liquid holdup and pressure loss. Correlations for liquid holdup and friction factor were developed for predicting pressure gradients for two-phase flow in pipes at all angles for many flow pressure gradients for two-phase flow in pipes at all angles for many flow conditions. Introduction The prediction of pressure drop and liquid holdup occurring during two-phase gas-liquid flow in pipes is of particular interest to the petroleum, chemical, and nuclear industries. In the nuclear industry, two-phase flow occurs in reactor cooling equipment, and liquid holdup greatly affects heat transfer. Two-phase flow occurs frequently in chemical processing, and the design of processing equipment and piping systems requites knowledge of pressure drop, liquid holdup, and often flow pattern. In the petroleum industry, two-phase flow occurs in pipelines and in oil and gas wells. More than one-half the natural gas gathered in the U. S. flows in two-phase flowlines. Most gas-producing wells produce some liquid and most oil wells produce some gas. As the natural reservoir energy is depleted, many wells are equipped with artificial-lift systems such as gas lift. To design these systems, a method of predicting two-phase-flow pressure gradients is required. pressure gradients is required. Although extensive research in two-phase flow has been conducted during the last 25 years, most of this research has concentrated on either horizontal or vertical flow. Several good correlations exist for predicting pressure drop and liquid holdup in either predicting pressure drop and liquid holdup in either horizontal or vertical flow, but these correlations have not been successful when applied to inclined flow. Many gathering lines and long-distance pipelines pass through areas of hilly terrain. This presents no problem in single-phase flow because the potential energy problem in single-phase flow because the potential energy lost going uphill is regained in the downhill section. This is not the case for two-phase flow, because the liquid holdup, and thus the mixture density, are usually much lower in downhill flow. For this reason, pressure recovery in the downhill sections is usually pressure recovery in the downhill sections is usually neglected in the design of two-phase pipelines. The number of directional or inclined wans is increasing as the search for petroleum moves into previously unexplored areas. In offshore drilling, previously unexplored areas. In offshore drilling, several directional wells are usually drilled from one platform for economic reasons. Deviations of 35 deg. to platform for economic reasons. Deviations of 35 deg. to 45 deg. from the vertical are common. In the permafrost areas of Alaska and Canada, the cost of drilling-rig foundations and the difficulty of transportation require that several wells be directionally drilled from one location. Existing vertical-flow correlations frequently fail to predict pressure gradients in these wells within acceptable limits. Gathering lines from offshore wells usually are laid along the sea floor that slopes up to the shore. The elevation pressure gradient in a pipeline with a very small upward inclination from horizontal can be much greater than the frictional pressure gradient. Therefore, in order to predict pressure drop, the liquid holdup must be accurately predicted. The ability to predict liquid holdup also is essential for designing field processing equipment, such as gas-liquid separators. JPT P. 607

Summary Oil/water flow-pattern transitions in horizontal pipes have been studied both experimentally and theoretically. A new state-of-the-art oil/water test facility was designed, constructed, and operated. A transparent test section (5.013-cm inside diameter x 15.54 m long) can be inclined at any angle, to study both upward and downward flow simultaneously. Mineral oil and water were the working fluids (µo/µw=29.6, po/pw=0.85, and o=36 dynes/cm at 25.6°C). A new classification for oil/water flow patterns based on published and acquired data is proposed. Six flow patterns were identified and classified into two categories: segregated flow and dispersed flow. Stratified flow and stratified flow with some mixing at the interface (ST&MI) are segregated flow patterns. The dispersed flow can be either water dominated or oil dominated. A dispersion of oil in water over a water layer and an emulsion of oil in water are water-dominated flow patterns. An emulsion of water in oil and a dual dispersion are oil-dominant flow patterns. The oil/water flow-pattern transitions for light oils are predicted using the two-fluid model and a balance between gravity and turbulent fluctuations normal to the axial flow direction. Stability analyses reveal that the stratified/nonstratified transition must be addressed with the complete two-fluid model. Stratified flow is predicted by the viscous Kelvin-Helmholtz (KH) analysis while inviscid KH theory predicted the ST &MI flow pattern. For the dispersed flow pattern, the predicted drop sizes from the Hinze and Levich models are modified to account for the effect of the dispersed phase concentration. The controlling parameter for the coalescence phenomena is the water fraction. The model performance is excellent and compares well with published data. Introduction The need for reliable design methods for multiphase flow has been the driving force behind an extensive research effort in this area, especially for gas/liquid flow, over the past 30 years. Recently, the industry has turned its attention towards the understanding of the simultaneous flow of gas/oil/water mixtures. However, the limiting case where no gas phase is present has received inadequate attention. Dynamic flow characteristics of oil/water mixtures are important in applications such as designing water-lubricated pipelines, production strings in oil wells, and artificial-lift methods. Understanding of oil/water flow behavior in pipes can be crucial in determining the amount of free water in contact with the pipe wall that could cause corrosion/erosion problems. Oil/water flow behavior is also important in arriving at the correct interpretation of the response of production-logging instruments. The performances of separation facilities and multiphase pumps are a strong function of the upstream flow pattern. A knowledge of the distinctive features of oil/ water mixtures, together with those for gas/liquid systems, can be used in the future as a basis to understand the more complex case of gas/oil/water mixtures.

No abstract

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^

Extensive experimental data were acquired for oil-water flow in horizontal pipes for a very wide range of oil viscosity. Pressure drop, flow rate, input water fraction, in-situ holdup, mixture temperature, and flow pattern data were obtained for 612 oil-water tests in 1.5-in. pipe, and 587 tests in 1-in. pipe. Oils with viscosities of 4.7, 58, 84, and 115 cp were used in the 1.5-in. runs, while the 1-in. tests used 237-cp and 2116-cp oils, all measured at 70 degrees F. Mixture velocities varied from 1.5 to 12 ft/s, while input water fractions ranged from 0.05 to 0.90, and mixture temperatures were between 50 and 98 degrees F. A new correlation is proposed for the prediction of the inversion point of an oil-water dispersion. It was found that the input water fraction required to invert the dispersion decreases with increasing oil viscosity. Pressure drop due to friction was also found to increase Pressure drop due to friction was also found to increase abruptly when the flowing oil-water mixture reached the inversion point where the external phase inverted from water to oil. Two pressure-gradient prediction models are presented; one for stratified, and the other for homogeneously dispersed oil-water flows. Comparison between model predictions and experimental data shows satisfactory predictions and experimental data shows satisfactory agreement. Experimental oil-water flow pattern maps were developed. The existing flow pattern in an oil-water mixture depends primarily on mixture velocity, input water fraction, and primarily on mixture velocity, input water fraction, and oil viscosity (only when oil is the external phase). Introduction Cocurrent flow of two immiscible liquids such as oil and water in horizontal pipes is a common occurrence in the petroleum industry. The need to understand the nature petroleum industry. The need to understand the nature and flow behavior of this type of multiphase flow is very complicated due to the existence of various flow patterns and different mechanisms governing them. This phenomenon, coupling with the hard-to-predict rheological behavior of an oil-water system, have been the driving force behind a considerable research effort in this area. The results of these studies would lead to better predictions of the existing flow pattern and its associating pressure gradient, yielding a better designing scheme for such system. This paper investigates the simultaneous flow of different oil-water fluid systems. The study involves gathering approximately 1,200 oil-water experimental data points in 1-in. and 1.5-in. horizontal pipes, for a wide range of flow conditions (flow rates, temperatures, input water fractions, etc.), and also for a wide range of oil viscosities. A correlation is presented, based upon this study and some other published results, for the prediction of the inversion point of an oil-water dispersion system. Two pressure-gradient point of an oil-water dispersion system. Two pressure-gradient prediction models were also developed for two different prediction models were also developed for two different oil-water flow patterns; namely, stratified and homogeneous. In addition, typical experimental oil-water flow pattern maps are also presented. LITERATURE REVIEW An oil-water mixture flow presents a unique and complex problem for pipeline transportation of heavy crude oils in problem for pipeline transportation of heavy crude oils in the petroleum industry due to its complicated rheological behavior, and the vast difference in pressure gradients encountered for different flow patterns. For the homogeneous flow pattern, the system of two immiscible liquids, such as oil and water, could become even more complex since the resulting mixed fluid can turn into an emulsion. An emulsion is a dispersed system which consists of two immiscible liquids. An unstable emulsion, or a dispersion, is an emulsion which can separate into the original phases within a reasonable period of time at rest. These dispersions can also exhibit Newtonian or non-Newtonian rheological behavior; depending on each specific oil-water system. Another phenomenon that further complicates an oil-water dispersion system is the phase inversion phenomenon, in which the dispersed phase inversion phenomenon, in which the dispersed phase switches to the continuous phase. phase switches to the continuous phase. P. 155