Pressure Loss Correlations Research Articles

Analysis of Two-Phase Tests in Large-Diameter Flow Lines in Prudhoe Bay Field

Abstract A total of 29 two-phase flow tests was conducted in two 3-mile-long flow lines in the Prudhoe Bay field of Alaska. Of these, 11 were for a 12-in.-diameter line and 18 were for a 16-in. line. Nine of the tests were in slug flow, and 20 were in froth flow. Flow rates, inlet and outlet pressures, and temperatures were measured for each test. Gamma densitometers were used to monitor flow pattern and to determine mixture densities and slug characteristics. It was found that a modified Beggs-Brill1 pressure-loss correlation predicted culled data to within − 1.5% on the average compared with + 11.4% for a modified Dukler-Eaton2,3 correlation. Very little scatter was observed with either method. Analysis of flow-pattern observations showed that none of the slug-flow tests were in the Schmidt4 severe slug region characterized by extremely long slugs. It also was found that the slug/froth (dispersed) flow-pattern boundary existed at a much lower liquid flow rate than predicted by either Mandhane et al.5 or Taitel and Dukler.6 Four of the slug-flow tests in 16-in. lines lasted for a sufficient time to permit statistical analysis of slug-length distributions. Sixteen additional tests on 4- and 7-in.-diameter pipe reported by Brainerd and Hedquist* were analyzed statistically. It was found that slug lengths could be represented by a log-normal distribution. A regression analysis approach was successful for estimating the mean slug length for stabilized flow as a function of superficial mixture velocity and pipe diameter. The extreme percentiles of the slug-length distribution then can be computed using standard probability tables, making possible probability statements about expected maximum slug length. A mechanistic analysis of the slug-flow tests resulted in equations for predicting slug velocities, liquid holdup in both the liquid slug and the gas bubble, and the volumes of liquid that are produced and overrun. These parameters are important for predicting liquid-slug effects on separator performance.

Evaluation of Inclined-Pipe, Two-Phase Liquid Holdup and Pressure-Loss Correlation Using Experimental Data (includes associated paper 8782 )

A 2-in. (5.1-cm) diameter, 550-ft (168-m) long pipeline was designed andconstructed in a hilly terrain configuration. Two-phase-flow holdup andpressure-loss correlations were evaluated using gas/water data obtainedfrom experiments. Accurate predictions were obtained using the Beggs andBrill correlation and a combination of Beggs and Brill and Guzhov et al.correlations. Introduction Two-phase flow in pipelines located in hilly terrain isencountered in the petroleum industry frequently. Inoilfield gathering systems, two-phase mixtures mustbe transported from the wells to the separationfacility. Because of the problems associated with oiland gas production offshore, it is usually necessaryto have a common pipeline for the liquid and the gasstreams. It is especially important to have gooddesign methods for sizing these pipelines. When designing two-phase pipelines, pressurelosses and liquid holdup must be predicted.The liquid holdup is defined as the fraction of pipe occupied by liquid during two-phase flow. A value ofliquid holdup also is an important considerationwhen designing separation equipment, slug catchers, and pumps. A great deal of research has been conducted inhorizontal and vertical two-phase flow, and severalgood correlations exist for these cases. However, only limited research has been performed in inclinedtwo-phase flow. The main objective of this study was to design andconstruct an experimental facility that could be usedto investigate two-phase flow phenomena in pipelines laid in hilly terrain. The secondary objective of thisstudy was to evaluate several existing correlations forpredicting liquid holdup and pressure losses usingdata obtained from the test facility. Literature Review Several authors have investigated inclined two-phaseflow to some degree. An actual field study of a 16-in.pipeline was conducted by Flanigan in 1958.Pressure drops over various sections of the line weremeasured. He concluded that the inclination of thehills had no effect on the pressure drop and that nopressure recovery existed in the downhill sections.Flanigan's design method included using thePanhandle equation to calculate friction loss and anelevation factor to determine the loss caused byelevation. It is possible that Flanigan's elevationfactor could include some pressure recovery in thedownhill sections. This is because any pressure loss, not accounted for by the friction term, is assumed tobe elevation loss on the uphill side. The overallpressure drop was used in the development of thiscorrelation; consequently, any pressure recovery thatmight have been present is included in the elevationterm. A two-phase inclined flow study was conducted in1967 by Guzhov et al. Their data were taken in 2-in.pipe inclined at angles between 9 degrees fromhorizontal. In development of the correlation, two flowregimes were consideredplug and stratified. A mixtureFroude number and the gas input fraction were usedto predict flow pattern. In stratified flow, there is oneliquid holdup expression for uphill flow and one fordownhill flow. JPT P. 1198^

A Statistical Evaluation of Methods Used To Predict Pressure Losses for Multiphase Flow in Vertical Oilwell Tubing

Several methods for predicting pressure losses for upward, concurrent, continuous, multiphase flow in vertical oilwell tubing were tested against measured pressure losses from 726 well tests. This comparison of well known pressure-loss correlations reveals the relative strengths and weaknesses of each correlation and should be useful in selecting satisfactory methods for various applications. Introduction Several correlations have been published that can be used to predict pressure losses in vertical oilwell tubing for the simultaneous, upward, concurrent, continuous flow of oil, water, and gas. Because of the extreme complexity of multiphase flow, the proposed correlations are by necessity highly empirical. The validity of the correlations is then somewhat limited to the quality and scope of the data upon which they are based. Therefore, some correlations perform quite well for cases in the range of the data used in developing the correlation but fail for other applications.The purpose of this study is to ascertain the accuracy of several pressure-loss prediction methods in terms of flow variables familiar to the practicing engineer. The results of the study should assist the petroleum production engineer in selecting the most petroleum production engineer in selecting the most accurate method for his problem and also should indicate the general accuracy to be expected from the methods.The correlations included in the study are those of Poettmann and Carpenter, Baxendell and Thomas, Poettmann and Carpenter, Baxendell and Thomas, Duns and Ros, Fancher and Brown, Hagedorn and Brown, and Orkiszewski. Each of these correlations was proposed specifically for predicting pressure losses in vertical oilwell tubing for the upward flow of multi-phase well fluids.The pressure-loss prediction methods were programmed for the IBM 360 computer and tested programmed for the IBM 360 computer and tested against 726 well tests from field and experimental wells. A statistical analysis was made to find the most acceptable method for different ranges of flow variables and also the method having the best over-all performance for predicting the measured pressure performance for predicting the measured pressure losses. Pressure-Loss Prediction Correlations Pressure-Loss Prediction Correlations The six correlations chosen for study will be discussed briefly. A review of the history and content of multi-phase flow literature and a more detailed discussion of individual correlations may be found in Brown.The correlation of Poettmann and Carpenter is a relatively simple and practical one to predict pressure losses in flowing wells. However, its very pressure losses in flowing wells. However, its very simplicity limits its accuracy. The method was included in this study for comparison, and because it served as a starting point for later correlations.Poettmann and Carpenter correlated the irreversible energy losses of 49 well tests with a Fanning-type friction term. The friction term was related to the numerator of the Reynolds number for the well fluid mixture. No attempt was made to account for liquid holdup (volume fraction liquid in a pipe section), but rather an average density of produced fluids corrected for down-hole conditions was used. The correlation reproduced the measured pressure gradients to an average deviation of 1.8 percent and a standard deviation from the average of 8.3 percent. JPT P. 903