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MODELING AND SIMULATION OFHYDROGEN SULFIDE REMOVAL FROMPETROLEUM PRODUCTION LINES BYCHEMICAL SCAVENGERSKrishnaswamy Rajagopal a , Rogério Lacerda b , Ivan Slobodcicov c &Eugenio Campagnolo ca Laboratório de Termodinâmica e Cinética Aplicada (LATCA),Escola de Química, Universidade Federal do Rio de Janeiro , Rio deJaneiro, Brazilb Departamento de Engenharia Química e do Petróleo , Escola deEngenharia, Universidade Federal Fluminense , Niterói, Brazilc Centro de Pesquisa e Desenvolvimento (CENPES), Tecnologiade Recuperação e Análises de Reservatórios e de Elevação eEscoamento, PETROBRAS , Rio de Janeiro, BrazilPublished online: 12 May 2009.

To cite this article: Krishnaswamy Rajagopal , Rogério Lacerda , Ivan Slobodcicov & EugenioCampagnolo (2009) MODELING AND SIMULATION OF HYDROGEN SULFIDE REMOVAL FROM PETROLEUMPRODUCTION LINES BY CHEMICAL SCAVENGERS, Chemical Engineering Communications, 196:10,1237-1248, DOI: 10.1080/00986440902832100

To link to this article: http://dx.doi.org/10.1080/00986440902832100

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Modeling and Simulation of Hydrogen SulfideRemoval from Petroleum Production Lines

by Chemical Scavengers

KRISHNASWAMY RAJAGOPAL,1

ROGERIO LACERDA,2 IVAN SLOBODCICOV,3 ANDEUGENIO CAMPAGNOLO3

1Laborat�oorio de Termodinamica e Cinetica Aplicada (LATCA), Escola deQuımica, Universidade Federal do Rio de Janeiro, Rio de Janeiro, Brazil2Departamento de Engenharia Quımica e do Petr�ooleo, Escola deEngenharia, Universidade Federal Fluminense, Niter�ooi, Brazil3Centro de Pesquisa e Desenvolvimento (CENPES), Tecnologia deRecuperacao e An�aalises de Reservat�oorios e de Elevacao e Escoamento,PETROBRAS, Rio de Janeiro, Brazil

The in-line scavenging of hydrogen sulfide is the preferred method for minimizing thecorrosion and operational risks in offshore oil production. We model hydrogen sul-fide removal from multiphase produced fluids prior to phase separation and proces-sing by injection of triazine solution into their gas phase. Using a kinetic model andmultiphase simulator, the flow regimes, amounts, and composition of three phasesare determined along the horizontal and vertical flow path from subsea well toseparator tank. The flow regimes were found to be slug flow or intermittent flow.The highly reactive triazine is destroyed on contact with water phase flowing nearthe wall. We have simulated the hydrogen sulfide concentration profiles for differentamounts of gas injection. The results are compatible with the available fielddata from an offshore oil well and are useful in determining the injection rates ofexpensive chemical scavengers and optimal gas injection rates.

Keywords Hydrogen sulfide removal; Gas lift injection; Multiphase flow reactor;Sour oil production; Triazine scavenger solution

Introduction

In several petroleum reservoirs, the concentration of hydrogen sulfide (H2S) has beenobserved to increase unexpectedly in gaseous, oil, and aqueous phases of producedfluids. This concentration is typically measured in parts per million by volume(ppmv) in the gas phase relative to a partition from oil and an aqueous phase witha pH equal to or less than 5 at standard temperature and pressure (STP), of 20�C and1 atm absolute pressure. When the concentration of H2S exceeds 3 ppmv in the gas

Address correspondence to Krishnaswamy Rajagopal, Laborat�oorio de Termodinamica eCinetica Aplicada (LATCA), Escola de Quımica, Universidade Federal do Rio de Janeiro, Av.Hor�aacio Macedo, 2030. Ed. do Centro de Tecnologia, Bloco E – sala 209, C.P. 68502, CidadeUniversit�aaria, CEP 21949-900, Rio de Janeiro – RJ, Brazil. E-mail: raja@eq.ufrj.br

Chem. Eng. Comm., 196:1237–1248, 2009Copyright # Taylor & Francis Group, LLCISSN: 0098-6445 print=1563-5201 onlineDOI: 10.1080/00986440902832100

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phase, the oil well is deemed to be sour, and precautions are necessary in design andoperation of production, transport, and storage equipment due to H2S toxicity, cor-rosion, plugging of reservoir formations, and increased sulfur content of producedoil. Some oil fields in the North Sea and Campos Basin (Brazil) have turned sourafter a few years of injection of seawater for improved recovery of oil (Eden et al.,1993). Many studies have attributed this souring to the activity of sulfate-reducingbacteria and resultant production of biogenic H2S, except in a few cases of very highpressure reservoirs where there is evidence for a geochemcial mechanism as well(Farquhar, 1998). Many production facilities were unfortunately previously designedand built without considering the effect of these organisms on their operation andmaintenance. From the experience of North Sea oil fields, we can expect about10% of the oil wells to suffer from increased corrosion of tubing, casing, and produc-tion facilities, iron sulfide deposition, and injection and wellbore plugging, as well assafety, health, and environmental concerns during the economic production life ofthe field.

The souring of petroleum reservoirs caused mainly by sulfate-reducing bacteriacan increase the concentration of hydrogen sulfide in produced fluids to the point ofmaking it necessary to inject expensive chemical scavengers in production pipelinesso that the corrosion and operational risks can be minimized. In-line scavenging ofhydrogen sulfide is the preferred method for production of crude oil containing lowhydrogen sulfide levels from subsea wells, especially where the well is tied back via aflowline to a host facility at which there is no provision for H2S scavenging and=orwhere a H2S removal facility is too expensive and=or impractical to install (Nagl,2001). As a result of this method, the hydrogen sulfide content of the crude oil thatis delivered to the platform is reduced to safe and commercially acceptable levels andreaction by-product formation is manageable. The formation water provides a car-rier phase for some of the reaction products and enhances the dispersion of someinsoluble reaction products in the coproduced aqueous phase.

We model this chemical process using available field data so that the cost ofremoval of hydrogen sulfide (H2S) can be reduced by determining optimal gas injec-tion rates as well as the rate of injection of chemical scavengers in production lines.The proposed methodology is also useful in selecting alternative scavengers. In theliterature, models have been proposed for treating single-phase natural gas withliquid scavengers (Fisher et al., 2003). There is little information about in situremoval of hydrogen sulfide from multiphase streams.

Chemical System

The chemical system considered is a subsea flowline connecting a mature subsea oilwell to an offshore production facility, schematically shown in Figure 1. The reser-voir fluids, namely, formation water, crude oil, and its associated gas, flow intoproduction lines at point 13. The oil phase is initially above the bubble point pres-sure, and the gas lift process is used to transport and lift the reservoir fluids fromthe well to the production platform. The widely used liquid chemical scavenger1,3,5-tris (2-hydroxyethyl)-1,3,5-triazinane (‘‘triazine’’) is atomized into the lift gaspipeline and the mist is homogenized by flow. Then the lift gas with the scavengermist is continuously injected into the production line through a mandrel aftersegment 8. The scavenger droplets disperse through the produced fluid substantiallyhomogeneously because of the natural turbulence of the fluid flow. As the pressure

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drops below the bubble point, a gas phase containing part of the H2S is formed. Thedroplets of triazine injected into the gas phase decompose H2S by the nucleophilicsubstitution of sulfur into the triazine ring, and the droplets encountering waterphase are rapidly hydrolyzed in a competing reaction. The reactions take place inthe multiphase flow along the flowline. The reaction products disperse in the liquidphase. The lift gas is recovered from the oil at a separation stage and is reused.The geometry of chemical system is shown in Table I.

Simulation of the Chemical System

The chemical system considered corresponds to an existing offshore oil well in theCampos Basin of Brazil, which has turned sour after injection of seawater for severalyears. Besides design data, the available field data are flow rates of reservoir fluids:839m3=day of oil, 1,300m3=day of water, and 79,000m3=day of free gas for a lift gasinjection rate of 171,552m3=day. All flow rates cited in this work are in STP m3 perday (at standard temperature and pressure of 293.15K and 101325 Pa) per day. Theconcentration of H2S in the separator reduced from 450 to 10 ppmv after injection of2.4 STP m3=d of a commercial chemical scavenger, triazine. The system is modeledusing available data along with several physical properties measured for the purposeof this study (Table IIA). The simulation is done in three steps: (1) multiphase simu-lation to determine the pressure, temperature, velocity of each phase, liquid holdup,and flow rates of each phase, (2) estimating the phase distribution of hydrogensulfide from total amount or from gas phase concentration, and (3) estimating

Figure 1. Flow path and flow regimes of the chemical system.

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Table

I.Segments

offlow

path

from

offshore

platform

tosubseawell,em

piricalcorrelationsusedformultiphase

flow,predictedflow

regim

ein

each

segmentfordifferentinjectionratesoflift

gas

Segment

no.

Flow

line

Length

[m]

Tube

diameter

[inch]

Lining

diameter

[inch]

Angle=

horizontal

[deg]

Ambient

temperature

[�C]

Correlationused

Predictedflow

regim

efor

40–600%

gaslift

1Subsealine

790

6.00

090

25.0

DunsandRos(1963)

Slug

2Subsealine

150

6.00

02.3

4.0

BeggsandBrill(1973);

Palm

er(1975)

Interm

ittent

3Subsealine

1200

6.00

02.3

4.0

BeggsandBrill(1973);

Palm

er(1975)

Interm

ittent

4Subsealine

80

4.00

02.3

4.0

BeggsandBrill(1973);

Palm

er(1975)

Interm

ittent

5Well=column

18.4

3.95

8.681

90

4.7

Orkiszewski(1967)

Slug

6Well=column

482.6

4.88

8.681

90

22.1

Orkiszewski(1967)

Slug

7Well=column

544

4.88

8.681

69.6

40.5

Orkiszewski(1967)

Slug

8Well=column

250

4.88

8.681

59.2

48.2

Orkiszewski(1967)

Slug

Liftgasinjection

N.A

.4.88

8.681

58.8

57.7

Orkiszewski(1967)

Bubble

9Well=column

222.7

4.88

8.681

58.8

57.7

Orkiszewski(1967)

Bubble

10

Well=column

358

4.88

8.681

54.2

68.2

Orkiszewski(1967)

Bubble=

liquid

11

Well=column

50

3.94

8.681

31.6

69.1

Orkiszewski(1967)

Liquid

12

Well=column

53

4.88

8.681

27.3

70.0

BeggsandBrill(1973);

Palm

er(1975)

Liquid

13

Well=column

194

4.88

8.681

11.5

70.0

BeggsandBrill(1973);

Palm

er(1975)

Liquid

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scavenging reaction rates and gas phase concentration of hydrogen sulfide along theflow path. The proposed methodology is described below for each of the steps.

Multiphase Flow Simulation

The flow in the production tubes was simulated using in-house software. The follow-ing three components of pressure drop along a flow path were considered: hydro-static head, velocity head, and frictional loss. Frictional loss occurs both betweenthe fluid and the pipe and between the phases. The flow rates and properties ofthe phases determine the physical arrangement of the fluid, and this arrangementdetermines the pressure drop. The conceptual model was developed according tothe data available and the basic assumptions on multiphase fluid hydrodynamicsoutlined above. All the main features of the production line were represented inthe simulator environment in order to perform the calculations. The simulationmodel was applied to predict the flow regime and pressure drop along the productionline from the reservoir up to the platform.

Table IIA. Measured properties of the fluids

Reservoir fluids Scavenger solution

Property ValueTemperature

�CViscosity

cPDensityg=cm3

Temperature�C

SurfacetensionmN=m

Density offormationgas

0.710(air¼ 1.0)

10 160.88 1.0319 — —

Densityof lift gas

0.640(air¼ 1.0)

20 86.23 1.0246 19.9 30.04

Density ofproducedgas

0.660(air¼ 1.0)

30 49.41 1.0172 30.4 29.12

Gas-oil ratio 86.0(m3=m3)

40 30.03 1.0097 40.8 28.34

Densityof oil

0.935(water¼ 1.0)

50 19.25 1.0021 50.0 27.9

Viscosityof oilat 30�C

218.70 (cP) 60 12.93 0.9943 60.5 27.05

Viscosityof oilat 50�C

69.36 (cP) 70 9.03 0.9864 — —

Wax appearancetemperature

20.0 (�C) 80 6.51 0.9782 — —

Density offormationwater

1.030(water¼ 1.0)

90 4.82 0.9698 — —

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For the purpose of simulation, the flowline from surface to reservoir was dividedinto 13 segments based on the inclination and location, whether the line is locatedunder the seabed or not. Suitable empirical correlations were used to determinethe flow regime and pressure drop along the tubes. The pressure drop due to fittingsand valves was included by manufacturer’s specifications. Each segment was dividedin to sub-segments for calculating pressure drop and heat transfer more precisely.Table I also shows the empirical multiphase correlation used and the predicted flowregime in different segments for a range of injected lift gases. Figure 1 shows the evo-lution of the flow regimes along the line. Between the reservoir and the point of thegas lift injection the flow regime goes from liquid phase to bubbling flow, and afterthe gas lift injection up to the platform the flow regime is slug. The heavier waterphase flows generally as an annulus near the wall. The temperature, pressure, andflow rates of oil, water, and gas phases were determined along the flow path by thissimulation for different gas lift rates, ranging from 40% to 600% of field flow rate.

Estimation of Phase Distribution of H2S

From the available literature data (Eden et al., 1993) we developed a correlation toestimate the equilibrium constant of hydrogen sulfide between oil and water phases(K oil=water) from temperature, pressure, and gas-oil ratio. The equilibrium Henry’sconstant KH2S for the gas=oil phases and for gas=water phases was correlated withtemperature at low pressures. The correlation is shown in Figure 2. In this condition,the equilibrium constants are independent of composition and pressure and thedistribution coefficient K oil=water is calculated at each temperature (Figure 3).The salt concentration of the particular case under study was similar to that in theliterature data used. If the compositions of the phases are very different from theliterature case, it is advisable to determine the equilibrium constant by experiment.The thermodynamic equilibrium of oil, water, and gas phases was calculated usingthe Sour Peng-Robinson (Sour PR) model. This model combines the Peng-Robinsonequation of state and Wilson’s API-Sour Model for handling sour water systems andcan be applied to sour water processes containing hydrocarbons, acid gases, andH2O. The method uses Wilson’s model to account for the ionization of the H2S,

Figure 2. Linear correlations for equilibrium constants of oil and formation water.

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CO2, and NH3 in the aqueous water phase. The fugacities of the vapor and liquidhydrocarbon phases as well as the enthalpy for all three phases were calculated usingthis equation of state. The K-values for the aqueous phase were calculated usingWilson’s API-Sour method (American Petroleum Institute, 1978).

The Pressure-Volume-Temperature (PVT) tests were done to determine thereservoir fluid composition and physical properties like dissolved gas content andresidual oil density. The liberated gas and residual oil compositions were obtainedby gas chromatography. The H2S concentration was determined by spectroscopy.The oil phase is considered as a semi-continuous mixture with components andfractions based on normal boiling point. The fractions and the residue are consideredas pseudo-components. The binary interaction parameters are obtained by tuningwith PVT tests. Table IIB shows the reservoir fluid composition and physical pro-perties obtained from the PVT analysis.

The pressure variation along the tube was calculated using the Peng-Robinsonequation of state, considering the composition of the fluids without hydrogensulfide.

Estimation of Reaction Rates

Buhaug (2002) reported the kinetics of triazine liquid reacting with gaseous hydrogensulfide and buffered water solution. In the scavenging reaction, the concentrationvariation of triazine in contact with hydrogen sulfide gas was determined by isotopicnuclear magnetic resonance (NMR) studies and the rate was determined to be firstorder in hydrogen sulfide concentration:

d½T�=dt ¼ �ka½THþ�½HS�� for pH>10 ð1Þ

with ka¼ 9.1� 107Ka [mol �2* s] where Ka is the acid constant of triazine in

solution. The author has also concluded that the reaction will be first order and fastfor pH< 10. The reported kinetic constants may, however, have large errors,

Table IIB. Reservoir fluid composition

Component Mole fraction Pseudo-component Mole fraction

H2S 70 ppm C6 fraction 0.015Methane 0.449 C7 fraction 0.022CO2 0.000 C8 fraction 0.041Nitrogen 0.003 C9 fraction 0.043Ethane 0.031 C10 fraction 0.040Propane 0.018 C11 fraction 0.039i-Butane 0.005 C12 fraction 0.037n-Butane 0.025 C13 fraction 0.045i-Pentane 0.004 C14 fraction 0.038n-Pentane 0.005 C15 fraction 0.040

C16 fraction 0.031C17 fraction 0.027C18 fraction 0.025C19þ residue 0.018

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especially if extrapolated to low pH values. The triazine is rapidly hydrolyzed oncontact with water with reported kinetics of

d½T�=dt ¼ �kH½T�½H� for pH < 10 ð2Þ

with kH¼ 1.42� 106 s�1 at 22�C and 3.40� 108 s�1 at 60�C. The hydrolysis will bealmost instantaneous for pH values of 5 or below.

We model the kinetics of hydrogen sulfide removal by triazine injection with thefollowing considerations. The triazine solution is atomized into gas stream in nearlyuniform droplets about 10 mm diameter. The smaller and larger droplets have smallsurvival times. A computational fluid dynamics (CFD) simulation of the flow sup-ports this consideration. The highly reactive triazine in the droplets will be destroyedalmost instantly on contact with water phase flowing near the wall. The rate ofremoval of hydrogen sulfide is limited by the rate of mass transfer of H2S fromthe gas phase to scavenger solution droplets. The oil, water, and gas phases are inthermodynamic equilibrium along the flow path.

The rate of removal of H2S is estimated using a model that combines mass trans-fer resistance and reaction. Fisher et al. (2003) have used this model for natural gastreatment. The amount transferred is estimated using the rate equation:

dyH2S

dz¼ KGaPyH2S

Gð3Þ

where yH2Sis mole fraction of H2S in the gas phase; G is molar gas velocity, mol=m2s;

Z is tube length, m; KG is overall mass transfer coefficient, mol=m2 s bar; a isinterfacial area, m2=m3; and P is pressure, bar.

The pressure and molar gas velocity will vary along the path. We have estimatedthe rate constant (KGa) using the field data of H2S concentration with and withoutinjection of scavenger solution for same rate of lift gas injection and flow rates in the

Figure 3. Equilibrium constant K oil=water for hydrogen sulfide at low pressures (unasso-ciated hydrogen sulfide and formation water with pH¼ 5).

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offshore oil well under study. The H2S concentration at the entrance was obtained bymass balance at steady-state operation of the well without injecting triazine. KGawas determined from the measured operational concentration of H2S while injectinga known rate of triazine solution with known lift gas rate.

Results and Conclusions

The chemical system was simulated using the above methodology for different liftgas injection rates with and without scavenger solution. For the case of normalgas lift operation injecting 171,552 STP m3=day (100% gas lift) without scavengersolution, the temperature and pressure profiles are shown in Figure 4. The flow ratesof different phases are shown in Figure 5. The flow regimes were found to be gener-ally slug flow or intermittent flow. The amounts and concentration of hydrogensulfide are shown in Figures 6 and 7. The simulated value of 448 ppmv compares wellwith the measured value of 450 ppmv in the separator.

The hydrogen sulfide concentration profile for the case of production withoutlift gas and without scavenger solution is shown in Figure 8. The simulated concen-tration is 1635 ppmv. The production was shut down in the field when the con-centration exceeded 1000 ppmv. Figure 8 also shows the hydrogen sulfideconcentration profile for the case of injection of 1 million STP m3=day (582.9%gas lift). The simulated value is 108 ppmv in the separator compared to the expectedvalue of about 100 ppmv.

The normal gas lift operation (100% gas lift) with injection of 2.4m3=dayof liquid triazine was simulated. The hydrogen sulfide concentration profile is shownin Figure 8. The methodology effectively correlates the measured concentration of 10ppmv at the separator. The rate constants were re-estimated considering that the rate

Figure 4. Pressure and temperature profile along the flow path (gas lift of 171,552 STPm3=day without scavenger solution).

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constant proportionately varies with the square root of absolute temperature. Theeffect on the profile was negligible.

In all cases studied, the proposed model and methodology of simulation werefound to be effective in simulating the chemical system. The simulation studiesindicate the need for better atomization so that the gas phase concentration of

Figure 5. Flow rates of gas, oil, and water phases (gas lift of 171,552 STP m3=day withoutscavenger solution).

Figure 6. Distribution of hydrogen sulfide among the three phases (gas lift of 171,552 STPm3=day without scavenger solution).

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H2S can be reduced to acceptable levels immediately after the Christmas tree, as thepipelines were of less noble material with little resistance to corrosion by H2S. Theproposed methodology can be readily used for evaluating any scavenger with knownkinetics. The accuracy of simulation can be improved by using measured distributioncoefficients of H2S between the oil, water, and gas phases.

Figure 8. Comparison of concentration of hydrogen sulfide in the gas phase with and withoutinjection of scavenger solution. Case 1, without injection of lift gas and scavenger solution, ~;case 2, with injection of lift gas of 171,552 STP m3=day without scavenger solution,.; case 3,with injection of lift gas of 1,000,000 STP m3=day without scavenger solution, �; case 4, withinjection of lift gas of 171,552 STP m3=day and 2.4m3=day of triazine, —.

Figure 7. Concentration of hydrogen sulfide in the three phases (gas lift of 171,552 STPm3=day without scavenger solution).

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Acknowledgments

The authors acknowledge the financial support of CENPES-PETROBRAS and ofMCT=FINEP=CTPETRO=PETROBRAS under the project number: FBR 2528-06,entitled, ‘‘Distribuicao do G�aas Sulfıdrico entre Oleos Pesados, G�aas Liberado e a Aguade Formacao nas Condicoes de Reservat�oorio.’’ The authors thank CNPq for thescholarship ‘‘Bolsa de produtividade’’ to Krishnaswamy Rajagopal and FINEP=CNPq for DTI scholarships to Ian Hovell and Luis Augusto Medeiros Rutledge formaking several experimental property measurements.

References

American Petroleum Institute. (1978). A New Correlation of NH3, CO2, and H2S VolatilityData from Aqueous Sour Water Systems, American Petroleum Institute, Washington, D.C.

Beggs, H. D. and Brill, J. P. (1973). The study of two-phase flow in inclined pipes, J. Pet. Tech-nol., 255, 607.

Buhaug, J. B. (2002). Investigation of the chemistry of liquid H2S scavengers, Ph.D. diss.,Norwegian University of Science and Technology, Faculty of Natural Sciences andTechnology.

Duns, H. and Ros, N. C. J. (1963). Vertical flow of gas and liquid mixtures from boreholes,paper 22–106, presented at the Sixth World Petroleum Congress, Frankfurt, 19–26 June.

Eden, B., Laycock, P. J., and Fielder, M. (1993). Oil Field Souring, HSE Books, Liverpool.Farquhar, G. B. (1998). Review and update of technology related to formation souring,

Corros. Prev. Contr., 45(2), 51–56.Fisher, K. S., Leppin, D., Palla, R., and Jamal, A. (2003). Process engineering for natural gas

treatment using direct-injection H2S scavengers, GasTIPS, 9(2), 12–17.Nagl, G. J. (2001). Removing H2S from gas streams: Four leading technologies are compared

here, Chem. Eng., 108(7), 97–100.Orkiszewski, J. (1967). Predicting two-phase flow pressure drops in vertical pipes, J. Pet.

Technol., 19, 829–838.Palmer, C. M. (1975). Evaluation of inclined pipe two-phase liquid holdup correlations using

experimental data, MS thesis, The University of Tulsa, Tulsa, OK, Department ofPetroleum Engineering.

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