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CONSIDERATIONS OVER THE INFLUENCE OF THE COMPOSITION OF WET NATURAL GAS REGARDING

THE VAPOR - LIQUID PHASE EQUILIBRIUM

Alina PRUNDUREL 1 , Cristian EPARU 1 , Victor CRISTOLOVEAN 2

1 PETROLEUM-GAS UNIVERSITY, Ploiești, Roumanie, 2 SC EGAS SRL, Brașov, Roumanie.

Abstract. Natural gas introduced into the transportation system must meet certain requirements. One of them is to limit the humidity. The water content of the natural gas transported according to pressure, temperature and composition, may be in the form of vapors or in a condensed form in the liquid phase. This paper addresses the problem of vapor-liquid phase behavior of wet natural gas for various percentages of humidity and different compositions, characterized by the molecular mass from the transportation systems. Keywords: gas; humidity; phase equilibrium; transmission.

1. INTRODUCTION

In accordance with the rules in force, the natural gas introduced by the producer in the natural gas transportation system must meet certain criteria, including limiting the amount of humidity. Reducing the amount of gas humidity is made in the de-hydratation stations, before the gas is introduced into the transportation system.

In all natural gas deposits, the water contains a certain saturation. Thus, the gas is saturated with water vapors, according to the pressure and the temperature of the deposit. On the other hand, during the movement/ transportation of gas to the well, the movable water of the deposit is engaged in the gas current and it is produced along with the gas. As a result, the gas extracted from the deposits contains varying fractions of water, in both the liquid and the vapor form.

The water content of the natural gas transported according to their pressure, temperature and com-position, may be in the form of vapors or in a condensed form in the liquid phase [1, 2]. If the water content of the gas is in the liquid phase, it may create problems for the transportation process [3]. Gas transportation pipes are placed in the soil, under the frost depth and go through various landforms, which determine, by the point of view of elevation, a different elevation for each pipeline.

Water flow in the liquid phase is uncoupled from the gas flow, which moves with high speeds. The liquid phase from the pipeline, with a high density compared to the gas, is strongly influenced by gravity, which leads to the accumulation of water

in low-lying areas, and these water accumulations create bottlenecks or gas locks along the pipes, affecting the gas flow process.

One of the main issues addressed and resolved in this paper is to clearly define the vapor- liquid phase behavior of wet natural gas. The wet natural gas forms a complex thermodynamic system, falling within the mixtures of actual/ real gas [4, 5, 6]. Since the composition of natural gas varies from one deposit to another, this paper will analyze the influence of natural gas composition on the vapor-liquid phase equilibrium and will present a cor-relation between the vapor-liquid equilibrium curve and the molecular mass of the gas.

2. VAPOR- LIQUID EQUILIBRIUM PHASE FOR WET NATURAL GAS

The composition of natural gas is determined by a chromatographic analysis. This analysis is done on dry natural gas. In order to study the vapor-liquid phase behavior of the wet gas using the Schlumberger software PVTi [7], a mixture of wet natural gas can be made by adding different percentages of water [8]. Figure 1 shows the phase envelope for a mixture of natural gas and 0.06 % mole of water.

The area of the figure is divided by the equi-librium curve into two distinct areas, one in which the water content of the natural gas is in liquid form and one, to the right, in which the water con-tent of the natural gas is in vapor form. The process is more complex because in the liquid phase, there is an aqueous solution of hydrocarbons [9].

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Fig. 1. Phase envelope for natural gas with 0.06 % humidity.

Table 1

Natural gas compositions

Component Formula M [kg/kmole] Composition1 Composition 2 Composition 3 Composition 4

%mole %mole %mole %mole

Methane C1 16.043 96.6826 96.7506 98.8257 93.208

Ethane C2 30.07 1.7315 1.6039 0.3078 5.7102

Propane C3 44.097 0.5682 0.5444 0.0538 0.0325

Iso-butane IC4 58.124 0.0958 0.086 0.0244 0

N-butane NC4 58.124 0.0942 0.0896 0.0093 0

Iso pentane IC5 72.151 0.0187 0.0173 0.0098 0

N-pentane NC5 72.151 0.0133 0.0124 0.0029 0

Hexanes C6 86.178 0.0019 0.0073 0.0072 0

Heptanes C7 100.205 0 0 0

N-octane C8 114.23 0 0 0 0

Nitrogen N2 28.013 0.7402 0.7902 0.6839 0.508

Oxygen O2 31.99 0.0058 0 0.0053 0

Carbon dioxide CO2 44.01 0.0479 0.983 0.0671 0.5412

Water * H2O 18 0 0 0 0

Total% 100.0001 100.8847 99.9972 99.9999

M composition [kg / kmole] 16.64746046 17.02781817 16.2286496 17.55796286

Our interest area, for natural gas transportation, is marked with the black rectangle, the upper limit being the pressures found in the pipelines.

3. THE INFLUENCE OF NATURAL GAS COMPOSITION OVER THE VAPOR- LIQUID PHASE EQUILIBRIUM

In order to determine the influence of the com-position over the vapor-liquid phase equilibrium of wet gas, there were chosen for analysis four natural gas compositions, which appear in the transportation systems. These are shown in Table 1. Each composition is characterized by the molecular mass of the mixture, calculated on the last line of the table. To each composition there was added sequentially the following mole percentages of water: 0.01; 0.02; 0.04; 0.06 0.08; 0.1; 0.2; 0.4;

0.6; 0.8; 1; 2; 3; 4; 5%. For all these mixtures there were made phase envelopes from which there were retained for analysis the values that define the equilibrium curve for the area of interest of the transportation system of natural gas through pipelines. For example, concerning the percentage of 0.06% water, the equilibrium curves, for the analyzed compositions, are shown in Table 2 and Figures 2-5.

All compositions and humidity percentages were analyzed in this way. It was found that the equation describing the vapor-liquid phase behavior is the same for each composition (1), and that the only ones differing are the coefficients values denoted by a, b and c.

xcxbxaey (1)

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For the analyzed compositions and the water percentage of 0.06%, the interpolation curves and

the values of the coefficients are presented in Figures 6 - 9.

Table 2

Values that define the equilibrium curve

Composition 1 Composition 2 Composition 3 Composition 4

T [grd. C] P [bar] T [grd. C] P [bar] T [grd. C] P [bar] T [grd. C] P [bar]

–21.2915 2.193686 –21.2915 2.165 –21.2915 2.193686 –21.2915 2.193686

–15.1452 3.880748 –15.1452 3.83 –15.1452 3.880748 –15.1452 3.880748

–11.2024 5.567809 –11.2024 5.495 –11.2024 5.567809 –11.2024 5.567809

–3.43259 11.20882 –3.43259 11.06224 –3.43259 11.20882 –3.54856 11.20882

1.090112 17.21455 1.090112 16.98944 1.090112 17.21455 0.974146 17.18969

4.217158 22.7918 4.221959 22.49375 4.291459 22.7918 4.132321 22.78237

6.251384 28.50346 6.259385 28.13466 6.369678 28.56689 6.14617 28.50644

7.622235 33.7105 7.63201 33.27387 7.760252 33.77327 7.485526 33.68689

8.65092 38.88095 8.662899 38.37814 8.814825 38.95971 8.483818 38.83286

9.405122 43.9159 9.419507 43.34967 9.597608 44.02374 9.206788 43.83661

9.94389 48.759 9.96076 48.13276 10.16587 48.90646 9.713493 48.63604

10.31524 53.38448 10.33462 52.70229 10.56704 53.58544 10.05258 53.2013

Fig. 2. Composition 1 – water 0.06%.

Fig. 3. Composition 2 – water 0.06 %. ]

Fig. 4. Composition 3 – water 0.06 %.

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Fig. 5. Composition 4 – water 0.06 %.

Fig. 6. Interpolation curve for natural gas with composition 1.

Fig. 7. Interpolation curve for natural gas with composition 2.

Fig. 8. Interpolation curve

for natural gas with composition 3.

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Fig. 9. Interpolation curve for natural gas with composition 4.

Tables 3 and 4 show the coefficients of equation (1) for the minimum and maximum compositions and for all analyzed water percentages. Table 3 presents the coefficients for composition 3, cha-racterized by the lowest molecular mass 16.2286496 kg / kmole, and Table 4 shows the coefficients for composition 4, which has the highest molecular mass 17.55796 kg/kmol.

Table 3

The coefficients of the interpolation equation, for composition 3

% water a b c

0,01 4,5365878 0,10286917 4512,0699

0,06 2,1876237 0,095375772 4,98E-09

0,1 1,5419029 0,089173748 4,72E-13

0,6 -0,1141249 0,064747525 3,34E-29

1 -0,44827045 0,058821328 9,39E-35

5 -1,1268235 0,042261986

Table 4

The coefficients of the interpolation equation, for composition 4

% water a b c

0,01 4,5465931 0,09946601 17940,399

0,06 2,1984692 0,09588344 9,31E-09

0,1 1,5438232 0,08995084 8,58E-13

0,6 -0,13908692 0,06549675 5,51E-29

1 -0,47203568 0,05936713 1,58E-34

5 -1,1560462 0,04260597

It was found that the dew point pressure varies

in inverse ratio with the molecular mass of the mixture. Thus, as the molecular mass is higher, the dew point pressure decreases, the temperature remaining the same.

In order to generate a synthesis equation ap-plicable for any value of humidity and for any

composition, there were generated regressions for the coefficients of the maximum and minimum compositions.

If the lowest molecular mass of the selected compositions is M1 and the highest molecular mass is M2, the equation which defines the dew point pressure at a temperature t , based on the percentage of water, is :

( )* * * tP Exp a b t c e= + + (2)

where: 123413 / MMxaxaMMxaa (3)

123413 / MMxbxbMMxbb (4)

123413 / MMxcxcMMxcc (5)

x represents the percentage of water in the mixture

( )3a x is:

ln( ) /y a b x c x= + + (6)

a = 0.51692606 b = –0.87605896 c = 0.010241145

( )4a x - is:

0.5 2ln( ) (ln )y a bx cx x d x= + + + (7)

a = 7.3225836 b = –7.7946477 c = 7.0551387 d = 0.025979524

( )3b x - is

1 2 xy a bx ce- = + + (8)

a = –6.8098929 b = 20.810392 c = 16.39296

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( )4b x - is

( )2 2 2 4( ) / 1y a cx bx dx= + + + (9)

a = 0.009968864 b = 49.946466 c = 0.22102254 d = 14.593110

Equation (2) with the coefficients defined in equations of (6) - (9), allows us to calculate the

dew point pressure for a natural gas mixture, with molecular mass M and the percentage of water x, the restriction being %3x , at a temperature t of the natural gas.

The results of using this equation are shown graphically in Figures 10 - 13, wherein the vapor-liquid phase behavior is shown for the five compositions of natural gas, with molecular mass of 16, 16.5, 17, 17.5 and 18 kg / kmole, for various percentages of water.

Fig. 10 Vapor-liquid phase behavior of the natural gas with humidity 0.01 %.

Fig. 11 Vapor-liquid phase behavior of the natural gas with humidity 0.06 %.

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Fig. 12 Vapor-liquid phase behavior of the natural gas with humidity 0.6 %.

Fig. 13 Vapor-liquid phase behavior of the natural gas with humidity 2.2 %.

4. CONCLUSIONS

The natural gas composition influences the vapor-liquid phase equilibrium of wet natural gas.

From the analysis and the examples given, we draw the conclusion that at the same temperature, the dew point pressure increases at the same time with the molecular mass of the mixture.

Based on the complex correlation from equa-tion (2), it can be determined, by calculating, the liquid-vapor equilibrium curve for various percen-tages of humidity and for different compositions characterized by molecular mass.

RÉFÉRENCES

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[2] S. Neacșu – Thermodynamics and Thermal Machines, Printeh Publishing House, Bucharest, Romania, p. 132-146 (2009).

[3] D.AL Stan, M. Ionescu –The Humidity of Natural Gas, National Gas Magazine, 1, p. 42-45 (2001).

[4] T. Ahmed – Hydrocarbon Phase Behavior, vol. 7, Contri-butions in Petroleum Geology and Engineering, Gulf Publishing Company, Tulsa, Oklahoma, p. 244-254 (1989).

[5] S. Promkotra – Phase Equilibria of Condensate and Natural Gas, Advanced Materials Research, 746, p. 529-532 (2013).

[6] C.H. Whitson, M.R. Brule – Phase Behavior, SPE Mono-graph vol. 20, Richardson, Texas, USA, p. 4-12 (2000).

[7] Schlumberger - PVTi (version 2010.1) Refence Manual (2010).

[8] F.M. Kazim – Quickly Calculate of the Water Content of Natural Gas, Hydrocarbon Processing, 75, p. 105-108 (1996).

[9] E.D. Douglas – Determination of Water Vapor and Hydrocarbon Dew Point in Natural Gas, Proceeding of International School of Hydrocarbon Measurement, Houston, Texas, USA, 476 (1991).