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EFFECT OF SOUR GAS ON WATER VAPOUR

SOLUBILITY IN NATURAL GAS

TPG4140: Natural Gas Project

By

Andalu Frida William

Syikilili Adela Musa

Mwita Ghati

Faculty of Science and Technology

Department of Petroleum Engineering and Applied Geophysics

NOVEMBER 2012

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Acknowledgement

In accomplishment of this semester mini-project we had a lot of support in advice and in

materials which helped us to produce this piece of work successfully.

Our sincere gratitude should go to our Natural Gas lecturer Prof. Jon Steinar Gudmundsson of

NTNU, Department of Petroleum Engineering and Applied Geophysics for his valuable

advice and materials which surely were fundamental in our project.

Also we appreciate the support from Mayembe Joao Bartolomeu a Phd Student at NTNU for

his help in using Hysys program in this project.

.

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Abstract

This project focused on the effect of sour gases on water vapor solubility in natural gas. Sour

gas compositions from Germany were studied and water content for the gas reservoirs were

calculated by using the empirical formulas developed byMohammadi et al. (2005). It wasfound that, sour gases have effect on water vapor solubility; it increases the soluble water in

natural gas .Cappeln has 0.18mol-% of sour gas equivalent and 40.08 % of water content.

Bentheim has 0.02mol-% of sour gas equivalent and 5.26 % of water content at reservoir

temperature of 360 K .Bentheim was set as an ideal case and the additional antifreeze required

to inhibit hydrate formation increased by 34.31 % for Cappeln gas reservoir. Non-associated

gas reservoirs contain small composition of sour gases compared to associated gas reservoirs

hence, the effect of sour gases on non-associated gas reservoirs may be ignored due to their

slight effect on water vapor solubility similar with that of sweet gas. In summary, companies

operating on nonassociated gas reservoirs with high concentration of sour gases will spend

more money for antifreeze to inhibit hydrate formation in the pipes, flow lines and processing

utilities due to the additional water contributed by presence of sour gases.

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Table of content

Acknowledgement ........................................................................................................................... II

Abstract .............................................................................................................................................. III

Table of content .............................................................................................................................. IV

List of tables ........................................................................................................................................ V

Table of figures .................................................................................................................................. V

1.0 Introduction ........................................................................................................................... 1

2.0 Parameters controlling gas composition .......................................................................... 2

2.1 Parameters controlling h2s content in natural gas .................................................................................... 2

2.2 Classification of sour gases........................................................................................................................ 3

3.0 Factors affecting water content in natural gas ............................................................... 4

3.1 Temperature and system pressure ............................................................................................................ 4

3.2 Gas gravity ................................................................................................................................................ 4

3.3 Salinity....................................................................................................................................................... 5

3.4 Presence of sour gas in natural gas ........................................................................................................... 6

4.0 Factors affecting solubility of gas in brine and water .................................................. 7

5.0 Methods to estimate water content .................................................................................... 8

6.0 Additional antifreeze required .......................................................................................... 10

7.0 Results and discussion.......................................................................................................... 11

8.0 Conclusion ................................................................................................................................. 15

9.0 Recommendation ................................................................................................................... 15

10.0 References .............................................................................................................................. 16

11.0 Appendix ................................................................................................................................. 17

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List of tables

Table 1: Different gas reservoirs with the sour gas composition ............................................................ 3

Table 2: German sour gas composition ................................................................................................. 17

Table 3: Urengoy gas composition Russia ............................................................................................. 17

Table 4: the gas reservoirs considered................................................................................................... 18

Table 5: The constants used for calculation in equation ....................................................................... 18

Table 6: Correction factors due to presence sours gases ....................................................................... 18

Table 7: The calculated water content by analytical method ................................................................ 19

Table 8: The percent increase of water.................................................................................................. 19

Table 9: Input data for Hysys ............................................................................................................ 20

Table of figures

Figure 1: Water content with system pressure and temperature ............................................................. 4

Figure 2: Water content with temperature with effect on gravity ......................................................... 5

Figure 3: Water content with temperature with effect on salinity ......................................................... 5

Figure 4: Water content with system pressure of H2S, CO2 and CH4 ...................................................... 6

Figure 5: Gas solubility in water and in brine .......................................................................................... 7

Figure 6: Graph of water content of sweet and sour gases with temperature ........................................ 11Figure 7: Graph of water content of sweet and sour gases with saturation pressure ............................. 12

Figure 8: Graph of pressure with temperature for Bentheim gas reservoir........................................... 13

Figure 9: Graph of pressure with temperature for Cappeln gas reservoir............................................. 14

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1.0IntroductionNatural gases are usually saturated with water at reservoir conditions. Dissolved water in the

gas phase may form liquid water phase, ice or gas hydrates during production, transportation

and processing. Forming a liquid water phase may lead to corrosion or two phase flow

problems. Gas hydrates or ice formation may also cause blockages, reduction in flow rates

and pressure losses in pipes and flow lines.

This project firstly, will find out different gas compositions of associated and non-associated

gas around the world that has different sour gas compositions. In additional to that, it will

bring out how different sour gases affect the amount of water content. The findings will also

show how sour gases affect water vapor solubility in natural gas. This will be done by

considering water content of a gas reservoir with sour gases and with the one without sour

gases composition. From this comparison, the discussion part will tell us whether this effect

can be ignored or something more should be proposed to solve out the problem of water in

natural gas.

Secondly, it will discuss on the methods used to determine the amount of water content in

natural gas having the effect of sour gases. It is necessary to be able to estimate the

equilibrium water content of sour gases as a function of system temperature, pressure and gascomposition. This is very important in order to enable engineers to calculate the amount of

water condensed as a result of changes in the system conditions. Furthermore, it will find out

factors affecting water content in natural gas and gas solubility in water.

Lastly, it will demonstrate the effect caused by the increased water content on the additional

amount of antifreeze required to inhibit hydrate formation and relate it to how hydrate

formation increases the operation cost of a given company.

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2.0 Parameters controlling gas composition

Amursky et al (1983) described the analysis of the geological-geochemical conditions under

which the different natural gas formed as well as the study of the variations in the distribution

of their fields show that the composition of a natural gas is dependent on some natura lfactors, the main of which are:

Lithofacies development of source-rock formations controlling the type andconcentration of organic matter (OM).

Catagenic intensity (maturity level). The process of lateral and vertical migration and hyper genesis, leading to the

redistribution of the useful components of natural gas.

2.1 Parameters controlling H2S content in natural gas

H2S generation and accumulation in the sulphate-carbonate formations of the largest gas

bearing basins may be described by the following scheme:

The zones of active biochemical and sulphur organic-thermo chemical processes oftenreplace and overlap each other in depth

The reaction intensity of biochemical and sulphur organic-thermo chemical processesdecreases drastically and practically 2.5-3.0 km below in subsurface.

The maximum possible H2S concentration, produced by the biochemical reactionsdoes not exceed one tenth or perhaps as low as one hundredth of a per cent, and for

sulphur-organic-thermo chemical processes only some percent; along the margins of

oil-and-gas-bearing basins, in the zones of aeration which reach down to depths of

500-600 m, and under tectonic-dynamical active conditions in the 1700-2000 m range.

Amursky et al.(2003)

Formation of H2S varies from one geological environment to another as explained above

leading to variable composition of H2S in gas reservoirs. This may be a reason to why othergas fields have H2S and some to lack H2S for example Tanzania and Norway has little or no

H2S.

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2.2 Classification of sour gases

Depending on the H2S concentration, the natural gases containing hydrogen sulphide was

divided into groups byAmursky (1983) as follows;

i). Practically H2S free H2S up to 0.0014 %

ii). Low sulphurous H2S from 0.0014-0.3 %

iii). Sulphurous H2S from 0.3-1.0 %

iv). Medium sulphurous H2S from 1 -5 %

V). Highly sulphurous H2S more than 5 %

Germany gas reservoirs were studied, for instance, Cappeln, Adorf,Sagermeer, Dtlingen,

Visbek, Siedenburg and Bentheim gas reservoir. According toMohammadi et al. (2005) the

correlations are valid for gas reservoir with methane composition of 70 % and

above.Therefore, the above gas reservoirs have met that criterion. The table below shows the

classification of the gas reservoirs used in this project according to the above classification

described byArmusky et al. (2003) .The calculated sour gas equivalent was used to categorize

the reservoirs in various groups as shown.

Table 1: Different gas reservoirs with the sour gas composition

Gas reservoirs CO2 H2S DescriptionS/N mol% mol%

1 Sagermeer 6.2 0.04 Low sulphurous

2 Cappeln 16.1 2.9 Medium sulphurous

3 Dtlingen 6.8 7 Highly sulphurous

4 Visbek 9 4.3 Medium sulphurous

5 Siedenburg 8.5 6.8 Highly sulphurous

6 Adorf 15.3 1.5 Medium sulphurous7 Bentheim 2.1 0.4 Sulphurous

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3.0 Factors affecting water content in natural gas

Water content in the gas reservoir is affected by temperature, system pressure, gas

composition, presence of salts (salinity in the reservoir) and gas gravity. Detailed discussion

on the factors affecting water content in natural gas is shown below.

3.1 Temperature and system pressure

Literature shows water content of natural gas is decreasing as system pressure increases. On

the other hand, water content increases with increase in temperature.Ahmed et al.(2007)

presented the figures which show the water content versus pressure and temperature. See

figure 1 below.

Figure 1: Water content with system pressure and temperatureAhmed et al. (2007)

3.2 Gas gravity

Presence of heavy hydrocarbon in a gas increases gas gravity which has some effects on the

water content of that gas.Mohammadi et al. (2005) stated the correction factor to take into

account the effect of gas gravity with temperature. Figure 2 below was established for mole

fraction of water vapor in sweet gas having gravity of 0.7 and sweet gas with gravity of 0.9,

both at 10 [MPa].Upper and Lower curves are for gas with gravity of 0.7 gravity of 0.9

respectively.

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Figure 2: Water content with temperature with effect on gravityGudmundsson (2012)

3.3 Salinity

Another factor affecting the water content of natural gas is presence of salts. Again in

Mohammadi et al. (2005) the correction factor to take in to account the effect of salts was

stated. The mole fraction of water vapor in natural gas in contact with water having 5 [%]

dissolved solids (salt) at 10 [MPa] system (reservoir) pressure is shown in figure 3 below

where upper curve is for gas in contact with water and lower curve is for gas in contact with

5 [%] saline water.

Figure 3: Water content with temperature with effect on salinityGudmundsson (2012)

0,000E+00

1,000E-02

2,000E-02

3,000E-02

4,000E-02

5,000E-02

6,000E-02

7,000E-02

0 20 40 60 80 100 120 140 160 180

T [C]

y

[-]

0,000E+00

1,000E-02

2,000E-02

3,000E-02

4,000E-02

5,000E-02

6,000E-02

7,000E-02

0 20 40 60 80 100 120 140 160 180

T [C]

y[

-]

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3.4 Presence of sour gas in natural gas

Wayne et al. (2012)also on their discussion about the sour/acid gases with water content of

natural gases said that, within the normal design range, carbon dioxide CO2 and hydrogen

sulphide exhibit unusual saturation water content characteristics compared to methane. Both

of these acid gases demonstrate higher saturation water content in the liquid and supercritical

(dense) phase than in the vapor phase. Hydrogen sulphide exhibits the biggest offset from the

vapor phase saturation at about 5:1 carbon dioxide pales in comparison at about 2:1 water

content capacity. This means that at a particular high pressure H2S can no longer exist as a gas

it changes rapidly to liquid form and the water content rises sharply and remain constant with

increase in system pressure as shown on the figure below. For CO2 it forms water gradually

with the increase in pressure.The effect of gas composition was taken into detailed

consideration to assess the effect of sour gases on water content in natural gas. The vivid

picture will be portrayed in the analytical determination of water content of the natural gas

Figure 4: Water content with system pressure of H2S, CO2 and CH4Wayne et al. (2012)

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4.0 Factors affecting solubility of gas in brine and water

Gas solubility in water and in brine was studied byDodson and Standing (1944). They

presented the experiment report which shows solubility of natural gas in brine decreases with

increasing total solids' content. A brine having a total solids' content of 30,000 ppm will haveonly about 90 per cent as much gas dissolved in it at 5,000 psi, absolute, and 200 deg F as will

fresh water at the same pressure and temperature. The figure below illustrates their finding.

Figure 5: Gas solubility in water and in brineDodson and Standing (1944)

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5.0 Methods to estimate water content

Estimating the water content of natural gases is necessary in many chemical and petroleum

engineering processes e.g. calculating the amount of water condensed in a pipeline for

designing hydrate inhibition strategy. Methods to estimate the amount of water vapor innatural gas have been reviewed by Carroll (2003) andMohammadi et al. (2005). To describe

how sour gases affect the water content in natural gas, semi-empirical correlations developed

and presented byMohammadi et al. (2005) was chosen to elaborate the effects of the above

factors on water content in natural gas. See equation 1 below.

T

pa

p

py

a

ww

2

1exp . (1)

Where pw [MPa] is the saturation pressure of water, p [MPa] the system pressure,

a1=11.81479, a2=0.92951 and T [K] the system temperature. The constants a1 and a2 were

obtained from methane data from 273.15 [K] to 477.59 [K], equivalent to 0 [C] to 204.44

[C].The above equation was used to calculate the amount of water in sweet gas, yw ideal in

table 8 in the appendix. The saturation pressure of water can be found from Steam Tables and

empirical correlations. In this context the empirical correlation was used as recommended by

Mohammadi et al. (2005) to determine saturation pressure in [MPa] and the temperature unit

in [K].

266 101653.4)ln(3037.7

2.7258649.73exp10 TT

Tpw . .. (2)

Mohammadi et al. (2005) stated that the correlation based on methane data could be used for

natural gas with methane content above 70 [%]. Such a methane concentration will cover

most of the natural gases encountered in the oil and gas industry. If many factors are

considered in calculation of water content it is important that all factors are multiplied as

shown in the equation below

idealsaltgravitysourreal yFFFy . (3)

The effect of gravity and salinity in water content has been explained theoretically in the

factors affecting water content in natural gas. However, in the analytical approach of

estimating water content they were neglected and only the effect of sour gas was considered.

A correction factor Fsour is used to correct for the effect of sour gases through the relationship

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sweetwsoursou rw yFy ,, .. (4)

Mohammadi et al. (2005) suggested the following correlation for the correction factor

0

3

00

2

0

11p

pcp

p

T

TcT

TcyF effectivesou r

.. (5)

The values for constants p0, T0 , c1, c2 and c3 are in table 5 in the appendix. The temperature T

and pressure p are the system (reservoir) values. Equation 5 above was used to develop Table

6 in appendix. However, instead of accounting for the effect of the different sour gases on

water content separately, it is customary to use equation 6 below for the equivalent mole

fraction of sour gases. Equation 6 below was used to calculate the yeffective in table 4 in the

appendix.

2275.0 COSHeffective yyy . (6)

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6.0 Additional antifreeze required

Presence of sour gases in natural gas tends to increase water content in natural gas resulting to

hydrate formation. In order to inhibit hydrate formation antifreeze is injected in natural gas so

as to depress the hydrate formation temperature and to lower the dew point of water. Inhibitorconsidered in this study was the mono ethylene glycol (MEG).Gudmundsson (2012) gives the

simplest correlation equation which was used to estimate the amount of the inhibitor required

to lower hydrate formation temperatureby using Hammerschmidts correlation equation

shown equation 7 and 8 below.

T=

.. (7)

T=Hydrate depression temperature,

Mw=Inhibitors molecular weight,

X= Inhibitors mass concentration and

K= Inhibitors constant.

Gudmundsson (2012)recommends the values forinhibitors constant and molecular weight

of MEG to be 1222 and 62.00kg/kmol respectively .Therefore, the required inhibitors

concentration of MEG was obtained from equation 8 below and the values is displayed in the

result section;

XMEG =

................................ (8)

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7.0 Results and discussion

The water content of sour gas from Germany gas reservoirs and for ideal sweet gas are shown

in figure 5.1 below

Figure 6: Graph of water content of sweet and sour gases with temperature

The above figure was plotted using information in table 7 in the appendix and it shows the

analytical results of calculated water content versus temperature using the equations

developed byMohammadi et al. (2005). The upper curve represents water content of Cappeln

gas reservoir which has high amount of sour gases of about 0.18 mol-% and methane

composition of 78.8 mol-%.At reservoir temperature of 360 K water content of Cappeln is

40.08 %. The lower curve is water content of sweet gas which is almost similar to that of sour

gas of Bentheim which is a non- associated gas reservoir of methane composition of 91.0

mol-% and sour gas composition of 0.02mol-%. The water content for both cases increases

simultaneously with temperature depending on the sour gas composition of a particular gas

field. For example, at the temperature of 360 K the water content at Cappeln field (sour gas

field) increases by 40.08 % while at Bentheim water increases by 5.26 %.

0,0000

0,0010

0,0020

0,0030

0,0040

0,0050

0,0060

0,0070

0,0080

300 320 340 360 380 400 420 440

Watercontent(yw

)

Temperature (K)

Water content of sour and sweet gases vs temperature

yw(sweet)

yw(sour)-

Sagermeer

yw(sour)-

Cappeln

yw(sour)-

Dtlingen

yw(sour)-

Adorf

yw(sour)-

Visbek

yw(sour)-

Bentheim

yw(sour)-

Siedenburg

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Also at the temperature of 390 K the water content at Cappeln increases by 46.54 % while

that of Bentheim increases by 6.11 %. The water content increase at various temperatures is

presented at table 8 in the appendix. Therefore, water content of sour gas is higher than that of

sweet gas if it is assumed that water content of sour gas is the sum of three components (water

content of sweet gas, CO2 and H2S)

Figure 7: Graph of water content of sweet and sour gases with saturation pressure

The above figure was also plotted using information in table 7 in the appendix. Water content

increases linearly with saturation pressure and with the increase in sour gases composition. As

seen above the sweet gas water content is less than for sour gases. The non-associated gas

reservoir (Bentheim) has the lowest water content compared to the rest which are typically

associated gas reservoirs. For example, at the saturation pressure of 0.007 MPa the water

content of Cappeln gas field which has also high sour gas composition after Cappeln

increases by 24.35 % while that of Bentheim increases by 3.2 % and the similar trend is

shown in table 8 in the appendix.

0,000

0,001

0,002

0,003

0,004

0,005

0,006

0,007

0,008

0,00 0,02 0,04 0,06 0,08 0,10

Watercontent(yw

)

Saturation pressure(Mpa)

Water content vs saturation pressureyw(Ideal)

yw(sour)-

Sagermeer

yw(sour)-

Cappeln

yw(sour)-

Dtlingen

yw(sour)-

Adorf

yw(sour)-

Visbek

yw(sour)-

Bentheim

yw(sour)-

Siedenburg

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Due to high increase of water content in natural gas by presence of sour gases, it is necessary

to calculate the additional amount of antifreeze required to inhibit hydrate formation. The fact

that, Bentheim and Cappeln gas reservoirs have lowest and highest water content respectively,

they were chosen for this case study to investigate the amount of antifreeze required to inhibit

hydrate formation and how it varies with the increase amount of sour gases present in natural

gas. By assuming some reservoir conditions of temperature and pressure ,gas compositions

from these gas reservoirs were fed to the Hysys to model the phase envelop and hydrate

curves. Hydrate depression temperatures were obtained from Hydrate curve shown in figure 7

and 8 below

Figure 8: Graph of pressure with temperature for Bentheim gas reservoir

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Figure 9: Graph of pressure with temperature for Cappeln gas reservoir

Hydrate depression temperature from the above figures for Bentheim and Cappeln are 6 oC

and 9 oC respectively by assuming reservoir pressure of 40 bars and temperature 0 oC.

Therefore, inhibitors mass concentration for Bentheim and Cappeln gas reservoirs was

calculated from equation 8 as shown below:

XMEGfor Bentheim

=

XMEG=0.2334

XMEG for Cappeln =

XMEG=0.3135

Increment due 0.18 % sour gas = (0.3135-0.2334)

=0.08

Therefore, % Increment of antifreeze =

X100

= 34.31%

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8.0 Conclusion

From this project it can be concluded that, the composition of sour gases in natural gas

increases the amount of water content directly proportional, that is the more sour gas the more

water content in natural gas. Cappeln was chosen to represent associated gas reservoirs sinceit has high sour gas equivalent and high water content of 0.1 8 mole-% and 40.08 %

respectively. Bentheim has 0.02 % sour gas equivalent and 5.26 % of water content thus the

effect of sour gases on water vapor in non-associated gas reservoirs can be ignored since their

behavior in water vapor is similar with that of sweet gas.

It was also found that, sour gases have effect on water vapor solubility; it increases the soluble

water in natural gas by 40.08 % when 0.18 mole-% of sour gas equivalent was present in

Cappeln gas reservoir and antifreeze required to inhibit hydrate formation increased by34.31%. Therefore, gas reservoirs with high concentration of sour gases will require more

antifreeze to inhibit hydrate formation in the pipelines, flow lines and processing utilities due

to additional water contributed by presence of sour gases.

9.0 Recommendation

It is recommended that, for non-associated gas reservoirs the effect of sour gases may be

ignored .However, for associated gas reservoirs the effect of sour gases in natural gas is

critical hence detailed research should be done pertaining the design of the system. Removal

of sour gases can be done first in the processing unit before transporting it in pipelines. In

addition to that, proper design should be done to combat the hydrate formation and corrosion

in the utilities.

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10.0 References

Amursky G.I, V.I. Ermakov, I.P. Zhabrev, V.I. Staroselsky and N. N. Solovyev. VNII Gas,

Ministry of Gas Industry, Moscow, USSR (1983).

Donson, C.R, I.B Standing.Pressure-Volume-Temperature and Solubility Relations for

Natural Gas Water Mixtures. Standard Oil Company of California, La Habra, Calof.Mach

1994.

Fattals,K.A.A.Prediction of Water Content in Sour Natural Gas.King Saul University

College of Eng.April 2007.

Gudmundsson, J.S. Flow Assurance Solids in Oil and Gas Production. Appendix L, Water

vapour in Natural Gas. Norwegian University of Science and Technology September 2012.

Gudmundsson, J.S. Pipeline Flow Assurance-

http://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGudmundssonFlowAssuran

ce2012.pdf.

Hrncevic, L., K. Simon, Z.Kistafor and M.Malnar. Sour gas Reservoir exploitation in

Croatia. University of Zagreb June 2011.

Istomin .V.A, R.S. Suleimanov, G.A. Lanchakov, A.N. Kulkov, V.A. Stavitskii, "Research

Institute of Natural Gases and Gas Technologies -VNIIGAZ, OAO. Russia. Presentation in

17th World Petroleum Congress September 1-5, 2002, Rio de Janeiro, Brazil.

Mohammadi, A. H., Chapoy, A., Tohidi, B., and Richon, D., A Semi-Empirical Approach

for Estimating the Water Content of Natural Gases, Ind. Eng. Chem.Res, 43(22) (2004),

7137-7147.

Wayne Mckay, James R. Maddocks, Acid Gas Dehydration-Is there a better way?Gas

liquid Engineering Ltd (2012).

http://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGudmundssonFlowAssurance2012.pdfhttp://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGudmundssonFlowAssurance2012.pdfhttp://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGudmundssonFlowAssurance2012.pdfhttp://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGudmundssonFlowAssurance2012.pdfhttp://www.ipt.ntnu.no/~jsg/undervisning/naturgass/lysark/LysarkGudmundssonFlowAssurance2012.pdf

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11.0 Appendix

Table 2: German sour gas compositionAmursky et al. (1983)Typical data of German sour gases

( mol %)

Compone

nt

sagerme

er

cappel

n

dtling

en

visbe

k

varnho

rn

buchhor

st

C1 88.7 78.8 78.6 82.9 64.9 69.8

C2+ 0.2 0.01 0.02 0.02 0.002 0.003

N2 3.9 2.19 7.3 3.5 5.3 2.5

CO2 6.2 16.1 6.8 9.0 7.3 26.4

H2S 0.04 2.9 7.0 4.3 22.4 1.1

Siedenburg Barenburg Adorf Bentheim

80.8 72.1 77.2 91.0

0 0 0.23 0.1

3.7 4.9 4.8 5.7

8.5 8.7 15.3 2.1

6.8 14.3 1.5 0.4

Table 3: Urengoy gas composition Russia

Istomin et al.(2002)

Component mol-%

C1 98.5-99

C2 0.06-0.1

C3 0.01

C4 -

C5+ 0.3-0.5

CO2 0.08-0.1

N2 0.5-1.0

H2S -

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For calculation with equivalent z-sour gas composition

Table 4: the gas reservoirs considered

Gas reservoirs H2S CO2 Sour equivalent

S/N mol% mol% mol %1 SAGERMEER 6,2 0,04 0,06232 CAPPELN 16,1 2,9 0,18283 DTLINGEN 6,8 7 0,12054 VISBEK 9 4,3 0,12235 SIEDENBURG 8,5 6,8 0,13606 ADORF 15,3 1,5 0,16437 BENTHEIM 2,1 0,4 0,0240

Table 5: The constants used for calculation in equation

c1 0,03185

c2 0,01538

c3 -0,02772

Po 0,1 Mpa

To 273,15 K

Table 6: Correction factors due to presence sours gases

Temperature

Systempressure

Sagermeer

Cappeln

Dtlingen

Adorf Visbek

Siedenburg

Bentheim

T(K) P(Mpa)

Fsour Fsour Fsour Fsour Fsour Fsour Fsour

310 5 1,030 1,087 1,057 1,078 1,058 1,041 1,011320 10 1,058 1,170 1,112 1,153 1,114 1,044 1,022330 15 1,083 1,243 1,161 1,219 1,163 1,047 1,032340 20 1,104 1,306 1,202 1,275 1,205 1,049 1,040350 25 1,122 1,359 1,236 1,322 1,240 1,051 1,047360 30 1,137 1,401 1,264 1,360 1,268 1,053 1,053370 35 1,147 1,433 1,285 1,389 1,289 1,054 1,057380 40 1,155 1,454 1,299 1,408 1,304 1,055 1,060390 45 1,159 1,465 1,307 1,418 1,311 1,055 1,061400 50 1,159 1,466 1,308 1,419 1,312 1,055 1,061410 55 1,156 1,457 1,301 1,411 1,306 1,055 1,060

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Table 7: The calculated water content by analytical method

The amount of water content in various gas reservoirs

Ideal Sagermeer Cappeln Dtlingen Adorf Visbek Bentheim Siedenburg

yw(sweet) yw(sour) yw(sour) yw(sour) yw(sour) yw(sour) yw(sour) yw(sour)

0,0007 0,0007 0,0007 0,0007 0,0007 0,0007 0,0007 0,0007

0,0006 0,0007 0,0007 0,0007 0,0007 0,0007 0,0006 0,0007

0,0007 0,0008 0,0009 0,0008 0,0009 0,0008 0,0007 0,0008

0,0009 0,0010 0,0012 0,0011 0,0012 0,0011 0,0009 0,0010

0,0012 0,0013 0,0016 0,0015 0,0016 0,0015 0,0012 0,0013

0,0015 0,0017 0,0021 0,0019 0,0021 0,0019 0,0016 0,0017

0,0020 0,0023 0,0028 0,0025 0,0027 0,0025 0,0021 0,0022

0,0025 0,0029 0,0037 0,0033 0,0035 0,0033 0,0027 0,0028

0,0032 0,0037 0,0047 0,0042 0,0045 0,0042 0,0034 0,0036

0,0040 0,0046 0,0058 0,0052 0,0056 0,0052 0,0042 0,0044

0,0049 0,0056 0,0071 0,0064 0,0069 0,0064 0,0052 0,0055

Table 8: The percent increase of water

Pw Sat Ideal Cappeln Adorf Bentheim

Mpa T(K) yw(sweet) yw(sour)%H20content yw(sour)

%H20content yw(sour)

%H20content

0,003 310 0,00066 0,00072 8,72 0,0007 7,84 0,0007 1,150,004 320 0,00062 0,00072 17,05 0,0007 15,32 0,0006 2,240,007 330 0,00072 0,00090 24,35 0,0009 21,88 0,0007 3,200,010 340 0,00091 0,00119 30,62 0,0012 27,52 0,0009 4,020,015 350 0,00118 0,00160 35,86 0,0016 32,23 0,0012 4,710,021 360 0,00153 0,00214 40,08 0,0021 36,02 0,0016 5,260,029 370 0,00197 0,00282 43,26 0,0027 38,88 0,0021 5,68

0,039 380 0,00252 0,00366 45,42 0,0035 40,82 0,0027 5,960,051 390 0,00318 0,00466 46,54 0,0045 41,83 0,0034 6,110,065 400 0,00397 0,00582 46,64 0,0056 41,92 0,0042 6,130,081 410 0,00488 0,00711 45,71 0,0069 41,08 0,0052 6,00

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Table 9: Input data for Hysys

Component Molecular weight M

kg/kmol

C1 16

C2+ 30

N2 28

CO2 44

H2S 34

Reservoir temperature 87oC

Normal boiling point of C2+ = -89oC

Reservoir pressure 50 bars