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Collaborating Authors
Brill, J.P.
Abstract The flow behavior in hilly terrain pipelines with low flow rates of gas and liquid is gravity dominated. For these conditions, steady or unsteady state flow can prevail, even for constant input gas and liquid mass prevail, even for constant input gas and liquid mass flow rates. The transient behavior of the flow is due to pipeline geometry and the compressible nature of the pipeline geometry and the compressible nature of the gas phase. The result is the occurrence of terrain induced slugging which can cause operational problems. problems. Severe slugging in a pipeline-riser system can be considered as a special case of terrain slugging in hilly terrain pipelines. For this case, the system consists of with a downward inclined section followed by an upward inclined section. Recently, an improved quasi equilibrium model has been developed to simulate the transient flow behavior in pipeline-riser systems. A new model is developed to simulate low velocity flow in hilly terrain pipelines by extending the improved severe slugging analysis. The model is based on fundamental principles and incorporates the physical phenomena. Flow instabilities can inherently physical phenomena. Flow instabilities can inherently be predicted by the model, and a separate stability analysis is not required. The new model developed for low velocity flow in hilly terrain pipelines can be utilized to predict the flow behavior under a wide range of flow conditions, including zero net liquid and gas flow, pipeline start up and shut down practices, the effects of pipeline start up and shut down practices, the effects of pipeline rupture, and variations of inlet flow rates or pipeline rupture, and variations of inlet flow rates or separator pressure. Simulation of a full scale field pipeline is presented to demonstrate the capabilities of pipeline is presented to demonstrate the capabilities of the proposed model. The results show that large amounts of liquid and gas can be produced in a short period of time due to the occurrence of terrain slugging, period of time due to the occurrence of terrain slugging, creating a potential operating problem at the outlet of the pipeline. Introduction Hilly terrain pipelines with low flow rates of gas and liquid are often encountered in nearly depleted fields and fields in their early development stage. The flow in these pipelines is gravity dominated. A description of the system configuration is given in Fig. 1. It consists of sections of upward inclinations (risers) followed by sections with downward slopes (downcomers). The inlet superficial velocities of the gas and the liquid are given by v sL1 and v sg1. The riser lengths are L r1, L r2, ...., L rn with inclination angles of 1, 2, โฆ, n. P. 25
- North America > United States (0.28)
- Asia > Middle East (0.28)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean (0.24)
- Overview > Innovation (0.54)
- Research Report > New Finding (0.34)
Intelligent Utilization of a Unified Flow Pattern Prediction Model in Production System Optimization
Arirachakaran, S. (Advanced Multiphase Technology Inc.) | Papadimitriou, D.A. (Advanced Multiphase Technology Inc.) | Jefferson, L.L. (Advanced Multiphase Technology Inc.) | Brill, J.P. (U. of Tulsa) | Shoham, O. (U. of Tulsa)
Abstract Accurate predictions of flow patterns for multiphase flow in pipes remain unresolved problems in petroleum engineering. Many 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 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 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 problems that depend on flow pattern predictions is the interpretation of results. The 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 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 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. potentially problematic. Introduction A production system that includes both well string and pipeline sections is usually operated under multiphase flow conditions. In wells, even for the case of so-called "oil" or "gas" fields, pressure and temperature drops as the pressure and temperature drops as the produced hydrocarbons rise to the wellhead. produced hydrocarbons rise to the wellhead. P. 503
- North America > United States > Texas (0.46)
- Asia > Middle East > Israel > Mediterranean Sea (0.34)
Summary This paper describes a new computer network, its implementation, the moderate costs involved, and the tremendous benefits it offers a petroleum research environment. Introduction The Tulsa U. Fluid Flow Projects (TUFFP) is an industry/university research consortium established in 1973 to investigate multiphase flow in pipes for the petroleum industry. Currently, TUFFP maintains three types of computing power: HP/Apollo UNIX-based workstations, Apple Macintoshes, and AT-class IBM PC's and compatibles. The PC's, and more recently the Macintoshes, are used for data acquisition in experimental research facilities. The data are then transferred to HP/Apollo workstations for analysis and future simulation. The results from the workstation analysis are then ported to the Macintosh system for further graphical analysis in the form of plots and for report generation. In the past, a primitive setup of RS-232 lines, modem line boosters, and KERMIT linked the IBM-AT and compatible systems with the HP / Apollos. However, data transfers of more than a few megabytes proved extremely time-consuming and unreliable at 9,600 baud. The Macintosh link with the HP/Apollo system provided a similar setup, but allowed only one Macintosh to be linked to the HP/Apollo system through a serial input/output (SIO) line. Thus, it was mandatory that a student be at that particular Macintosh to transfer files. Although this arrangement provided data-transfer capabilities, it was extremely primitive, tedious, and prone to bottlenecks. A more useful and versatile networking strategy was needed. The current TUFFP computer network is a state-of-the-art and user-friendly system. Users require no prior knowledge of networking protocol and can transfer files among many computers in the network. Researchers can then concentrate on their research without checking hardware connections and learning software communication commands. Moreover, the new network can accommodate growth and change as new needs are introduced and the user population increases.
Abstract The sour gas produced from the offshore Point Arguello oil field will be transported Point Arguello oil field will be transported through a pipeline consisting of offshore and onshore sections terminating at an onshore processing plant. Accurate prediction of the processing plant. Accurate prediction of the complex flow behavior of the fluid in both pipeline sections is essential for proper pipeline sections is essential for proper operation of the pipeline. The objective of this paper is to analyze and provide engineering paper is to analyze and provide engineering solutions for the operational problems occurring during the different production phases of the field. phases of the field. It was found that the Point Arguello pipeline would exhibit different flow pipeline would exhibit different flow behaviors, depending upon the input flow rates. A simplified, flow pattern dependent, transient two-phase flow simulator was used to predict this complex flow behavior. For low predict this complex flow behavior. For low input flow rates the offshore pipeline section would operate under slug flow conditions, with liquid accumulating in the line, and frequent pigging being required. For high input flow pigging being required. For high input flow rates, the offshore pipeline section would operate under stratified flow, resulting in less liquid accumulation and liquid being transported into the onshore section. These different operational modes play an important role in leak detection analysis. The rigorous analysis of the complex flow behavior presented in this paper provides solutions for proper operation of offshore wet gas pipelines. This includes solutions for liquid accumulation, Digging frequency, and pressure fluctuations for leak detection. pressure fluctuations for leak detection Introduction The produced gas and liquid from the Point Arguello Field are planned to be Point Arguello Field are planned to be separated at the Hermosa platform. The gas and liquid phases will be transported in two separate lines to shore. The gas pipeline is located between the Hermosa platform and the Gaviota gas plant. A schematic of the pipeline is given in Fig. 1. The pipeline consists of two sections; 1. An offshore section starting from the Hermosa platform and ending at the landfall. 2. An onshore section starting from the landfall and ending at the Gaviota gas plant. plant. P. 885
Abstract A comprehensive model is formulated to predict the flow behavior for upward two-phase flow. The comprehensive model is composed of a model for flow pattern prediction and a set of independent models for predicting the flow characteristics such as holdup and pressure drop in bubble, slug and annular flows. The comprehensive model is evaluated by using a well databank that is composed of 1775 well cases covering a wide variety of field data. The performance of the model is also compared with the six commonly used empirical correlations. The overall performance of the model is in good agreement with the data. In comparison with the empirical correlations, the comprehensive model performs the best, with the least average error and the smallest scattering of the results. INTRODUCTION Two-phase flow is commonly encountered in petroleum, chemical and nuclear industries. The frequent occurrence of two-phase flow presents engineers with the challenge of understanding, analyzing and designing two phase systems. Due to the complex nature of two-phase flow, the problem was first approached through empirical methods. Recently the trend has shifted towards the modeling approach. The fundamental postulate of the modeling approach is the existence of flow patterns or flow configurations. Various theories have been developed for the prediction of flow patterns. Separate models were developed for each flow pattern to predict the flow characteristics such as holdup and pressure drop. By considering flow mechanics, the resulting models can be applied to flow conditions other than used for their development with more confidence. The only studies published on comprehensive mechanistic modeling of two-phase flow in vertical pipes are by Ozon et al. and Hasan and Kabir. Nevertheless, more work is needed in order to develop models which describe the physical phenomena more rigorously. The purpose of this study is to formulate a detailed comprehensive mechanistic model for upward two-phase flow. The comprehensive model first predicts the existing flow pattern and then calculates the flow variables by taking into account the actual mechanisms of the predicted flow pattern. The model is evaluated against a wide range of experimental and field data available in the updated TUFFP well databank. The performance of the model is also compared with six empirical correlations used in the field.
SPE Members Abstract A comprehensive mechanistic model has been developed for gas-liquid two-phase flow in horizontal and near horizontal pipelines. The model is able first to detect the existing flow pattern, and then to predict the flow characteristics, primarily liquid holdup and pressure drop, for the stratified, intermittent. annular, pressure drop, for the stratified, intermittent. annular, or dispersed bubble flow patterns. A pipeline data bank has been established. The data bank includes large diameter field data culled from the A. G. A. database, and laboratory data published in the literature. Data include both black oil and compositional fluid systems. The comprehensive mechanistic model has been evaluated against the data bank and also compared with the performance of some of the most commonly used correlations for two-phase flow in pipelines. The evaluation, based on the comparison between the predicted and the measured pressure drops. predicted and the measured pressure drops. demonstrated that the overall performance of the proposed model is better than that of any of the proposed model is better than that of any of the correlations, with the least absolute average percent error and the least standard deviation. Introduction Prediction of flow patterns, liquid holdup and pressure loss for two-phase flow in pipelines is pressure loss for two-phase flow in pipelines is important for designing gas-liquid transportation systems. The traditional approach to solve the problem has been to conduct experiments and develop empirical correlations. Although these correlations have contributed significantly to the design of two-phase flow systems, they did not take into consideration the physical phenomena. physical phenomena. Since the mid 1970's. significant progress has been made in this area. Models have been developed to predict flow patterns. Separate Models have also been predict flow patterns. Separate Models have also been proposed for the prediction of the flow characteristics proposed for the prediction of the flow characteristics for each flow pattern, namely stratified flow, intermittent flow, annular flow and dispersed bubble flow. However, up to date, no study has been carried out to verify the consistency and the applicability of these models. The purpose of this study is to develop a comprehensive mechanistic model for two-phase flow in pipelines by combining the most recent developments in pipelines by combining the most recent developments in this area. The model is then evaluated against a field and laboratory measurement data bank, and compared with several commonly used empirical correlations. FLOW PATTERN PREDICTION MODEL When gas and liquid flow simultaneously in a pipe, the two phases can distribute themselves in a pipe, the two phases can distribute themselves in a variety of flow configurations or flow patterns, depending on operational parameters. geometrical variables as well as physical properties of the two phases. phases. P. 167
ABSTRACT Two options are available for separating the gas liquid mixture at the exit of a two phase flow pipeline operating under slug flow conditions. These are a traditional vessel type separator and a finger storage type slug catcher. Use of a vessel separator is usually due to space limitations that exist, for example, on offshore platforms. Fingerstorage slug catchers are the obvious choice for long, large diameter pipes, especially those which undergo pigging. They are more cost effective and more simple to construct and operate. In the past, sizing of finger storage slug catchers were based primarily on experience andrules of thumb. Not surprisingly, most of the existing slug catchers have been oversized. Withthe recent trend of using a subsea compact finger storage slug catcher upstream of the platform riser, the need for more accurate design methods is even more crucial. This paper presents a new, innovative approach for the prediction of the required dimensions of slug catcher fingers. The approach is based on the effect of the finger pipe diameter and inclination angle on the transition boundary between slug flow and stratified flow. Predictionof the slug characteristics at the slug catcherinlet, under normal flow or pigging conditions, are incorporated. Based on the new approach, the required length and optimal downward inclination angle of the fingers can be determined. The new approach has been used to design a finger storage slug catcher for actual field conditions. The effect of operational conditions, e.g. pipeline diameter and finger inclination angle on the required slug catcher dimensions isdemonstrated. INTRODUCTION Pipelines can be operated under two phase flow conditions for several reasons. In hostile environments such as arctic and offshore fields, oil and gas are often transported in a singlepipeline to reduce the construction cost. In natural gas transportation, due to pressure andtemperature drop during flow in the pipeline, condensation causing two phase flow may occur. Depending upon the operating conditions, normal or terrain induced slug flow, may develop. Also, artificial slugs, possibly the largest ones, can be created during the removal of accumulated liquid by a pigging (sphering) operation in gas pipelines. It is a common practice to install a slug catcher to accommodate liquid slugs at the exit of a pipeline. A slug catcher can serve as both a separator and as temporary storage. There are several unconventional slug catcher types, such as a project slug catcher, a self supporting fluid separator, and a flexible subsea slug catcher. However, the vessel and finger storage types of slug catchers are the most widely used in the petroleum industry. Use of traditional vessel type separators as slug catchers are mainly dictated by space limitation and relatively small slug sizes. A number of studies have been conducted to design such catchers4 . In references 4, 5, and 6 the acceleration of the slugs during their production into the catcher and resultant loadson bends, fittings and slug catcher internals have been investigated for a specific slug catcher.
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- (10 more...)
Summary Use of wellhead chokes to monitor and control well flow rates and to protect the reservoir from surface pressure fluctuations is quite common. This study investigates the use of multiple-orifice-valve (MOV) chokes in the critical-flow region. Experimental data collected for a high-pressure air/water system show that conventional relationships are not successful in analyzing the experimental data for MOV chokes. A new relationship based on the sonic velocity of two-phase homogeneous mixtures is developed for the prediction of the critical-flow transition. The procedure uses choking, rather than liquid sonic velocity, as the criterion for critical flow in the liquid phase. The procedure is iterative but compensates for its complexity with high reliability and generality. The new relationship is validated by experimental data. Introduction Wellhead chokes are installed on wells to control flow rates and to protect the reservoir and surface equipment from pressure fluctuations. Flow through the choke can be described as either critical or subcritical. In the critical-flow region, the mass flow rate reaches a maximum value that is independent of the pressure drop applied across the choke. Therefore, once critical flow is reached, any dis-turbance introduced downstream of the choke will have no effect on upstream conditions. Therefore, chokes are commonly operated under critical-flow conditions to isolate the reservoir from pressure fluctuations introduced by surface processing equipment. A second use of wellhead chokes is to monitor production rates by operating in the subcritical-flow region, especially when oil and gas are produced from offshore or hostile environments. For these applications, it is advantageous to use MOV chokes that allow the size of the choke opening to be changed while the choke is under pressure without interruption of production. With this feature, the pressure drop across the choke, and thereby manipulation of the flow rate, can be remotely controlled. Surbey et al. I discussed in detail the application of MOV chokes in the subcritical-flow region. This investigation presents the application of MOV chokes in the critical-flow region. The limitations of conventional correlations in predicting critical-flow behavior for MOV chokes is also discussed. A new correlation is presented to predict the transition between critical and subcritical flow that is applicable to conventional chokes as well. Literature Review Several investigators have published correlations to predict the tran-sition between critical and subcritical flow. Wallis developed relationship to predict the sonic velocity in a two-phase homogeneous mixture. The equation can be written as (1) The liquid sonic velocity, v*, is assumed to have a constant value of 4,950 ft/sec [1509 m/s] for water, and the gas sonic velocity, v* is calculated from (2) When the mixture velocity in the choke throat equals the sonic velocity predicted from Eq. 1, critical flow is reached. Fortunati proposed a different correlation to predict sonic velocity. Using a no-slip condition between the phases, he propose that the sonic velocity of the mixture be given by (3) which assumes no mass transfer between the phases. He also proposed a relationship to predict the flow rate in the critical flow region assuming a discharge coefficient ranging from 1.02 to 1.035, depending on choke size. Ashford and Pierce derived an equation to predict the upstream-to-downstream-pressure ratio at the critical-flow transition. The liquation assumed that the derivative of mass flow rate with respect to this pressure ratio is zero at critical-flow conditions. The inherent assumptions were that the gas expands polytropically, that no slippage occurs between the phases, that the liquid is incompressible, and that frictional losses are negligible in the choke. One of the uncertainties of the model, as stated by Ashford and Pierce, is the definition of p . Ideally, p is the lowest pressure reached in the choke. In practice, this value cannot be measured easily and without uncertainty. Using their relationship for the occurrence of critical flow, Ashford and Pierce developed an equation to predict critical flow rates. In predicting these flow rates, they pointed out the uncertainties involved in precisely measuring the downstream pressure. Sachdeva et al. extended the work of Ashford and Pierce and proposed a relationship to predict the critical pressure ratio. They assumed that the gas phase at the choke entrance contracts isentropically but expands polytropically. Their model showed improvement over the Ashford and Pierce relationship for their own data. In addition to the above relationships, several investigators used field data to develop correlations to predict flow rates in the critical region. These relationships are of the form (4) where A, B, and C are constants given in Table 1 for various investigators. Gilberts reported that his correlation is very sensitive to changes in choke size and that an error of 1/128 in. [0. 198 mm] in d can introduce errors of 5 to 20% in the calculations. Omaha et al. developed an empirical correlation based on dimensionless groups. Regression coefficients were determined with experimental data obtained from a high-pressure natural-gas/water system. Two difficulties were evident in the prediction of the transition between subcritical and critical flow for MOV chokes. First, the measurement of p was difficult because of peculiarities in the choke design. As a result, the downstream pressure was measured only for fully recovered flow. Second, the shapes of the choke openings vary with choke design and cannot be defined as a simple circular hole. As MOV chokes are closed, the shape of the opening becomes more and more noncircular, creating a problem in defining an equivalent circular diameter. In view of these difficulties, a different approach was taken in analyzing critical-flow data. This approach was also found to be suitable for conventional chokes operating in critical flow. Results and Discussion The experimental data were divided into two groups, subcritical and critical flow, on the basis of a comparison of the downstream-to-upstream-pressure ratio to literature correlations. When all three correlations predicted a given data point to be in the critical region, that point was assumed to be critical. All other tests were grouped in the subcritical region. This procedure was necessary because direct identification of critical two-phase flow was not possible owing to the design of the test facilities. The overall range of experimental parameters is given in Table 2.he simplest method to correlate the critical flow data was through the use of a Gilbert-type relationship, such as Eq. 4. SPEPE P. 142^
Abstract 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
Abstract The compositions of vapor and liquid phases of a multicomponent system are functions of pressure and temperature. Therefore, the phase behavior of a fluid transported through a pipeline must be coupled to the pressure-temperature calculation algorithm. Both the Soave Redlich-Kwong and the Peng-Robinson EOS's were considered. A new procedure to calculate pressure and temperature profiles for multicomponent two-phase flow in pipelines was developed. This method, based on direct flash calculations at each pressure and temperature of interest, was compared to the method used by previous investigators based on interpolation of external arrays of physical properties. The new procedure was found to be more accurate and easier to use than the one based on interpolation of external arrays. This was especially true when calculations were performed near the critical point. Introduction Prediction of pressure drop is a major objective in two-phase flow pipeline design. However, pressure drop calculations in the past were usually performed based on simplified assumptions with respect to the temperature distribution and phase behavior. The calculations were often performed under isothermal conditions or assuming a linear temperature profile along the pipeline. Mass transfer between the gas and the liquid phases was taken into consideration applying the "black oil" model. This model assumes a constant or empirically predicted composition for both phases. Rigorous prediction of temperature and mass transfer is essential for multicomponent or compositional flow, such as gas condensate or volatile oil systems. For such systems, compositions of the two phases are not constant, but vary significantly along the pipeline as a function of pressure, and especially temperature. Thus, the black oil model is inadequate to handle compositional systems, which should be treated by VLE calculations. The simultaneous prediction of pressure and temperature requires coupling of the momentum and energy balance equations. This leads to a double iterative computational procedure. Earlier attempts to simplify this procedure assumed - a constant or linear temperature profile. Other investigators simplified the energy equation in order to obtain an explicit expression for temperature. Schorre derived an equation to predict temperatures of gas flowing in a horizontal pipeline. He applied the energy equation, considering both heat transfer between the gas and the surroundings, and the Joule-Thompson effect. P. 219^
- North America > United States (0.46)
- North America > Canada (0.28)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)