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Equilibrium Water Content of High Pressure Acid Gases: a Mathematical Model Paper By: W. D. Monnery*, Xergy Processing Inc. W. Y. Svrcek, University of Calgary I. A. Alami, Saudi Aramco

Alami Svrcek Monnery Water Content Paper Rev 3.3

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Page 1: Alami Svrcek Monnery Water Content Paper Rev 3.3

Equilibrium Water Content of High Pressure Acid Gases: a Mathematical Model

Paper By:

W. D. Monnery*, Xergy Processing Inc.

W. Y. Svrcek, University of Calgary

I. A. Alami, Saudi Aramco

November 2006

* Author to whom correspondence should be addressed ([email protected])

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ABSTRACT

A new simple, theoretically-based model that predicts equilibrium water content of pure acid gas components and acid gas mixtures has been developed for a temperature range of 32 to 212 °F (0 to 100 °C) and a pressure range of 14.7 to 2,000 psia (101 to 14,000 kPa). This new model provides a quantitative estimate of changes in equilibrium water content of acid gas mixtures due to a change in system pressure, temperature, or composition. When compared to available experimental data, the new model has an absolute average error (AAE) of 14%. At pressures above 2,500 psia and where no experimental data exist, the new model compares very well to the industry-accepted software, including AQUAlibrium and VMGSim with an AAE of less than 8%.

INTRODUCTION

The most popular sulphur recovery method utilizes the modified Claus process in which a combustion furnace followed by a series of catalytic reactors are used to produce elemental sulphur from H2S. Since a Claus plant does not recover 100% of the sulphur, the tail gas is incinerated emitting SO2 and CO2 to the atmosphere. Due to high capital and operating costs as well as low demand and oversupply of elemental sulphur, acid gas re-injection into deep geological formations emerged as a viable option. In addition to providing a cost-effective alternative to sulphur recovery, the deep injection of acid gas reduces emissions of noxious substances into the atmosphere and alleviates the public concern resulting from sour gas production and flaring.

To effectively design an injection scheme, water content, phase behavior and physical properties of the acid gas mixture over the range of operating temperatures and pressures are required. Although phase behavior and physical properties are relatively well predicted with existing equations of state, water content is not (Clark, 1999). Our objective is to develop a theoretically based mathematical model that can be applied easily to predict the water content of acid gas mixtures at temperatures and pressures required by operating companies.

AVAILABLE MODELS

The problem of determining the water vapor content of sour natural gas is essentially that of calculating the composition of a mixture at certain temperature and pressure conditions. The methods available for calculating the water content of natural gas fall into three categories: (1) partial pressure approach (ideal model); (2) empirical plots and correlations; and (3) equation of state (Alami et. al., 2005). The first two approaches are limited either by the temperature and/or pressure of applicability or the H2S/CO2 concentration. Requiring the use of a computer, models based on equations of state perform better when interaction parameters used in the sophisticated mixing rules

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are based on experimental data. AQUAlibriumTM and VMGSim, as examples of this approach, have rigorous thermodynamic models specifically designed to calculate phase equilibria between vapor, aqueous liquid and non-aqueous liquid phases for systems containing light hydrocarbons, H2S, CO2 and water. The model parameters are extracted from experimental data by regression. This type of software is widely used in the gas processing industry. These approaches are reviewed briefly in the following sections.

1. Partial Pressure Approach (Ideal Model)

If the mixture were to act such that the vapor phase behaves as an ideal gas and the liquid phase behaves as an ideal solution, then the Raoult’s law and Dalton’s law can be used to describe the phase equilibria (Campbell, 1994):

(1)

and

(2)

Equating Raoult’s law and Dalton’s law for water “w” and rearranging:

(3)

Since water in almost immiscible in the hydrocarbon liquid phase, , is usually assumed to be equal to unity. Thus, the water mole fraction in the gas, , can be calculated as:

(4)

Ideal gas behavior is a limiting case and seldom do real gas/gas mixtures approach this condition except at low pressure and high temperature. Equation (4) is recommended for system pressures up to about 60 psia (400 kPa) (Campbell, 1994).

2. Empirical Plots and Correlations

i. McKetta and Wehe Correlation for Sweet Gases

Empirical plots are still widely used for engineering calculations. For a lean sweet natural gas, the chart developed by McKetta and Wehe (McKetta and Wehe, 1958) may be used. The McKetta-Wehe chart includes correction factors for formation water salinity and gas gravity. The water content shown on such charts is the maximum that the gas can hold at the pressure and temperature shown. It is fully saturated; the relative humidity is 100% or, stated in another way, the temperature is the water dew point temperature of the gas at the pressure and concentration shown. To facilitate the use of

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these charts, Behr (Behr, 1983) and later Kazim (Kazim, 1996) proposed alternative analytical expressions that fitted the natural gas dew point versus the water content.

The use of the mentioned charts and correlations, however, will result in serious errors if used for acid or sour natural gases since both H2S and CO2 can contain more water at saturation conditions than methane or sweet natural gas mixtures. Corrections for H2S and CO2 should be applied when the gas mixture contains more than 5% H2S and/or CO2 at pressures above 700 psia (4800 kPa) (Gas Processors Association, 1998).

ii. Maddox Correlation for Sweet and Sour Gases

To correct for significant acid gas (H2S and CO2) content, Maddox (Maddox, 1974) proposed the following correlation to calculate a weighted average water content, W:

(5)

Maddox assumed that nitrogen holds about 6 to 9% less water than methane and therefore can be included as a hydrocarbon, thus providing a small safety factor. This correlation provides adequate predictions at low pressures but tends to underpredict water content at high pressures.

iii. Robinson et al. Correlation for Sour Gases

The Robinson et. al. (Robinson et al., 1978) correlation for sour gases was developed based on a modification by Soave of the Redlich and Kwong (SRK) equation of state (Robinson, 1976). They generated a series of charts at pressures of 300, 1,000, 2,000, 3,000, 6,000 and 10,000 psia for temperatures from 50°F to 350°F. Robinson et. al considered all hydrocarbon components to be essentially CH4 and they assumed that CO2 carries only about 75% as much water as H2S over the entire pressure/temperature range. Therefore to use these charts, one uses the following relation to calculate the effective H2S dry gas composition:

(6)

The charts are applicable for H2S equivalent composition up to 40 mole % and the water content on these charts is reported in bbl/MMscf which can be converted as follows:

lbm/MMscf = 350 * (bbl/MMscf) (7)

lbm/MMscf: pound mass per million standard cubic feet

bbl/MMscf: barrels per million standard cubic feet

This method is cumbersome to use due to the multiple interpolations involved and cannot be used for pure acid gas mixtures, i.e., no hydrocarbons in the mixture.

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iv. Wichert and Wichert Method for Sour Gases

Wichert and Wichert (Wichert and Wichert, 2003) proposed a relatively simple acid gas correction based on the equivalent H2S content given by the following equation (similar to that of Robinson et al. but assumes that the CO2 carries only 70% as much water as H2S at the same conditions):

(8)

They presented a single chart where one could obtain a correction factor, Fcorr at a given temperature, pressure and equivalent H2S composition. The water content of the sour gas is then calculated by the following equation:

(9)

This method is applicable for temperatures from 50°F to 350°F and pressures from 100 psia to 10,000 psia. It is limited, however, to sour gas mixtures with an H2S equivalent concentration of 50% and cannot be used for acid gas mixtures (H2S and CO2).

3. Equation of State (EOS) Models:

i. Robinson et al. Approach

The Robinson et al. approach, mentioned earlier, originated from the concept of partial fugacity of component “i” in a mixture:

(10)

The equilibrium constant Ki, expressed in terms of the fugacity coefficient for a component in a mixture, is:

(11)

This predictive model was developed using the Soave modification of the Redlich-Kwong, (SRK), equation of state (Robinson, 1976). Sophisticated mixing rules were employed in which the interaction parameters were adjusted using the published data for binary mixtures of CH4-, H2S-, and CO2-H2O. Because of the limited amount of experimental data, this method tends to underpredict the water content of acid gas mixtures at high pressures. The method is not really suitable for manual calculations and requires programming into a computer. Finally, it should be limited to sour gas mixtures with up to 40 mole % equivalent H2S.

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ii. Sharma and Campbell Approach

Sharma and Campbell (Sharma and Campbell, 1969) developed a predictive method based on the McLeod corresponding states approach (McLeod and Campbell, 1969). The following steps summarize this method:

1. Calculate the Eykman Molecular Refraction (EMR) critical pressure, critical temperature and Z factor of the mixture using the McLeod corresponding states approach (Sharma, 1969).

2. Obtain K from a chart or calculate using the following equation:

(12)

3. From a generalized fugacity chart, determine the value of and hence for the gas mixture on a water-free basis

4. Determine the gas-water content from the following equation:

(13)

This model was originally intended for water content prediction of sour gases with less than 20 mole percent of any component except methane for a nominal temperature range of 100°F to 160°F and a pressure range of 200 psia to 2,000 psia (Sharma, 1969). The model, however, underpredicts the water content of acid gas mixtures with low hydrocarbon content, with errors, as high as 84%, especially at high pressures (Alami, 2004).

iii. Awad et al. Approach

Awad (Awad et al., 2002) proposed a new theoretically-based mathematical model that estimates the water content of a saturated natural gas, both sweet and sour, up to 10,000 psia and 460°F:

(14)

The model uses the Soave-Redlich-Kwong equation of state to calculate the fugacity coefficient of water in a natural gas mixture. It includes interaction parameters for water with hydrocarbons and water with CO2 and H2S. The calculation procedure, however, is tedious and must be computer-based.

This model, like Sharma-Campbell model, also suffered at high pressures and high acid gas contents, resulting in errors in excess of 85% (Alami, 2004).

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iv. AQUAlibriumTM

AQUAlibriumTM is a rigorous thermodynamic model specifically designed to calculate phase equilibria between vapor, aqueous liquid and non-aqueous liquid phases for systems containing light hydrocarbons, H2S, CO2 and water (Carroll, 2004). AQUAlibriumTM uses a Henry’s law approach for the aqueous phases and the Peng-Robinson Equation of State (PR EOS) for the non-aqueous phases (Clark, 1999). The model parameters are extracted from experimental data by regression.

v. VMGSimTM

VMGSimTM is a process simulator with over 5,500 components, designed to rigorously simulate chemical processes (Satyro, 2006). Although it has many property packages, for the prediction of water content of acid gases, it uses a rigorous thermodynamic model in its flash calculations based on a specially modified Peng-Robinson Equation of State (PR EOS) to describe both the vapor and liquid phases. The modified PR EOS has had the mixing rule interaction parameters regressed to a wide array of experimental hydrocarbon–water solubility data.

NEW MODEL

Sharma-Campbell and Awad et. al. models represented the best candidates for our objective of a simple but theoretically-based model since they were both based on the equilibrium requirement of equal fugacities. The Sharma-Campbell model was not used, due to the complexity involved in calculating the “true” critical properties, based on the EMR approach for gaseous mixture for the calculation of the compressibility factor and the fugacity coefficient. To accomplish our goal of a simple mathematical model, with a theoretical basis, it was decided to modify the Awad et al. model using a function of the following form (see equation 14):

(Awad Model) (15)where M is an empirical constant.

M was fitted and generalized using the available experimental data for pure H2S and CO2 from Selleck et al. (Selleck and et al., 1952) and Weibe and Gaddy (Wiebe and Gaddy, 1941) and from Clark (Clark, 1999) for acid gas mixtures. The modified model was developed first for pure acid gas components, H2S and CO2.

As can be seen from equations 12 and 14, fitting equations for the water vapor pressure and water fugacity at vapor pressure and system pressure were needed for both our approaches. Generalized equations for vapor fugacity and water molar volume were also required (Alami et. al., 2005) (Alami, 2004).

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Pure Components

Since analysis of the correction, to match the Awad et al. model to actual acid gas experimental data, looked like a cumulative probability curve, the following equation with the constraint shown was used.

.

(17)

where:

P = pressure in psia, Condition:

If the above condition is true, equation (32) will be evaluated and value of "M" retained. If the condition is not satisfied, "M" = C1, the transition of "M" from the value of C1 to the one calculated by equation (17) occurs at or near the pressure corresponding to the change in water content of the gas due to phase changes. Therefore, parameters C1, C2, C3 and C4 had to be fitted such that they can capture this transition at different temperatures and resulted in two sets of equations for these parameters.

For H2S, the equations were as follows:

(18)(19)

(20)

(21)

For CO2, the equations were: (22)

(23)(24)

(25)

Figures 1 and 2 show that the developed equations provide good predictions for the individual pure components, H2S and CO2, with maximum absolute average error (AAE) of less than 12% for both components.

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0.00000

0.00500

0.01000

0.01500

0.02000

0.02500

0.03000

0.03500

0.04000

0.04500

0.05000

0 500 1000 1500 2000 2500 3000 3500

Pressure, psia

yw

, m

ol

fracti

on

Experimental New Model Orig. Model

H2S-100F

Figure 1 Water Content of H2S vs. Pressure at 100 °F

0.00000

0.00100

0.00200

0.00300

0.00400

0.00500

0.00600

0.00700

0 500 1000 1500 2000 2500 3000 3500

Pressure, psia

Wate

r C

on

ten

t, m

ol.

fra

c.

Experimental New Model Orig. Model

CO2-100F

Figure 2 Water Content of CO2 vs. Pressure at 100 °F

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Page 10: Alami Svrcek Monnery Water Content Paper Rev 3.3

In Figure 1, the reader might notice that after about 1,000 psia, water content of H2S tends to slightly decrease with increasing pressure resulting in a deviation of about 22%. This is not physically correct at this point as experiments showed that once in the liquid or dense phase, water content of H2S slightly increases with increasing pressure (Carroll, 2002). This non-physical behavior can be attributed to the fact that the chosen function of “M” with its parameters does not increase enough to compensate for the decrease in water content as determined from the original model. After an extensive search in the fitting equations database, it is the opinion of the authors that the above relationships were the best describing functions for the behavior of pure H2S and CO2 and any mixture of them. The errors resulting from this trend are still very well within the experimental uncertainties.

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Acid Gas Mixtures

The next step in the development process was to combine these two sets of equations so that the model was applicable to acid gas mixtures. To maintain the simplicity of the model, the new “mixing rule” is only a function of composition.

Using the available water content data for acid gas mixtures, the parameters, C1, C2, C3, and C4 within the multiplier “M” were mixed and generalized as follows:

(28)

(29)

(30)

(31)

For pure components H2S or CO2, these mixture parameters will reduce to pure component Cis as one mole fraction goes to zero.

Results and Model Comparisons

For over 159 experimental water content data, Table 1 shows how the new model results compare to the original model and AQUAlibriumTM and VMGSimTM. Detailed model comparisons, along with comparison plots, are presented in Alami (Alami, 2004). The “original model” refers to the base model used in this study without the multiplier “M.” Figures 3 through 8 present some examples of visual comparisons of the model predictions and experimental data.

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Table 1 Models Comparison for the Total Data Set

Original Model AQUAlibriumTM VMGSimTM New Model

Sum of Abs. Errors: 5772 2317 2223 2153

Maximum Abs. Error: 91.93 80.36 92.3 46.59Abs. Average Error

(AAE): 36 15 14 14

Average Error (AE): -19.5 3.77 0.09 0.22Root Mean Square

(RMS): 46 21 20 17

Data Points 159

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0.00000

0.00500

0.01000

0.01500

0.02000

0.02500

0 500 1000 1500 2000 2500 3000 3500

Pressure, psia

Wat

er C

on

ten

t, m

ol.

frac

.

Experimental New Model Orig. ModelAQUAlibrium VMG

CO2-167F

Figure 3 Experimental vs. Models Water Content of CO2 at 167°F

0.00000

0.01000

0.02000

0.03000

0.04000

0.05000

0.06000

0 200 400 600 800 1000 1200 1400

Pressure, psia

yw, m

ol f

ract

ion

Experimental New Model Orig. Model

AQUAlibrium VMG

H2S-160F

Figure 4 Experimental vs. Models Water Content of H2S at 160°F

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0

0.0005

0.001

0.0015

0.002

0.0025

0.003

0.0035

0.004

0.0045

0.005

0 200 400 600 800 1000 1200 1400

Pressure, psia

Wat

er C

on

ten

t (m

ol f

rac.

)

Experimental New Model Orig. Model

AQUAlibrium VMG

20/80-86F

Figure 5 Expt vs. Models Water Content of 20 H2S/80 CO2 Acid Gas Mixture at 86°F

0

0.005

0.01

0.015

0.02

0.025

0.03

200 400 600 800 1000 1200 1400

Pressure, psia

Wat

er C

on

ten

t, m

ol f

rac.

Experimental New Model Orig. Model

AQUAlibrium VMG

80/20-140F

Figure 6 Expt vs. Models Water Content of 80 H2S/20 CO2 Acid Gas Mixture at 140°F

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0

0.001

0.002

0.003

0.004

0.005

0.006

0.007

0.008

0.009

0 200 400 600 800 1000 1200 1400

Pressure, psia

Wat

er C

on

ten

t (m

ol f

rac.

)

Experimental New Model Orig. Model

AQUAlibrium VMG

50/50-86F

Figure 7 Expt vs. Models Water Content of 50 H2S/50 CO2 Acid Gas Mixture at 86°F

0

0.001

0.002

0.003

0.004

0.005

0.006

0.007

0.008

0.009

0.01

200 700 1200 1700 2200

Pressure, psia

Wa

ter

Co

nte

nt,

mo

l fra

c.

Experimental New Model Orig. Model

AQUAlibrium VMG

25/75-104F

Figure 8 Expt vs. Models Water Content of 25 H2S/75 CO2 Acid Gas Mixture at 104°F

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New Model Extrapolation

The next step was to test the validity of the model at high pressures where no experimental data exist. Using AQUAlibrium and VMGSim, a set of 16 water content data points were obtained for different acid gas mixtures at 100 °F and pressures from 2500 to 5000 psia. Results of the new and original models water content predictions are presented in Tables 2 and 3 below. These tables clearly show that the new model extrapolates very well into high pressure regions with a maximum error of 11 – 18% and an average absolute error of 6 – 8%, compared to the rigorous models.

Although this comparison is between models because no experimental data exist, it clearly shows that the new model compares very well to the industry-accepted software.

Table 2 New Model Extrapolation Test

CO2 H2S T, °F P, psia Water Content, mol frac.

(AQUAlibrium)

Water Content, mol frac.

(New Model)

AE (New Model), %

Water Content, mol frac.

(Orig. Model)

AE (Orig. Model), %

0.9 0.1 100 2500 0.00583 0.00591 1.4 0.00154 -73.6

0.9 0.1 100 3000 0.0061 0.00597 -2.1 0.00148 -75.8

0.9 0.1 100 4000 0.00645 0.00585 -9.3 0.00140 -78.3

0.9 0.1 100 5000 0.00666 0.00569 -14.5 0.00136 -79.6

0.8 0.2 100 2500 0.00672 0.00684 1.8 0.00154 -77.1

0.8 0.2 100 3000 0.00702 0.00696 -0.9 0.00148 -79.0

0.8 0.2 100 4000 0.00741 0.00685 -7.6 0.00140 -81.1

0.8 0.2 100 5000 0.00766 0.00668 -12.8 0.00136 -82.3

0.5 0.5 100 2500 0.01046 0.01036 -1.0 0.00154 -85.3

0.5 0.5 100 3000 0.01078 0.01045 -3.0 0.00148 -86.3

0.5 0.5 100 4000 0.01124 0.01024 -8.9 0.00140 -87.5

0.5 0.5 100 5000 0.0115 0.00998 -13.2 0.00136

0.2 0.8 100 2500 0.01596 0.01527 -4.3 0.00154 -90.4

0.2 0.8 100 3000 0.0162 0.01488 -8.2 0.00148 -90.9

0.2 0.8 100 4000 0.01655 0.01420 -14.2 0.00140 -91.5

0.2 0.8 100 5000 0.0168 0.01376 -18.1Sum Errors: -115 -1314

Max. Abs. Error: 18.1 91.93AE, % -7.18 -83.68

AAE, % 7.58 83.68

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Table 3 New Model Extrapolation Test

CO2 H2S T, °F P, psia Water Content, mol frac.

(VMGSim)

Water Content, mol frac.

(New Model)

AE (New Model), %

Water Content, mol frac.

(Orig. Model)

AE (Orig. Model), %

0.9 0.1 100 2500 0.00547 0.00591 8.0 0.00154 -71.8

0.9 0.1 100 3000 0.00577 0.00597 3.5 0.00148 -74.4

0.9 0.1 100 4000 0.00616 0.00585 -5.0 0.00140 -77.3

0.9 0.1 100 5000 0.00636 0.00569 -10.5 0.00136 -78.6

0.8 0.2 100 2500 0.00626 0.00684 9.3 0.00154 -75.4

0.8 0.2 100 3000 0.00656 0.00696 6.1 0.00148 -77.4

0.8 0.2 100 4000 0.00695 0.00685 -1.4 0.00140 -79.9

0.8 0.2 100 5000 0.00725 0.00668 -7.9 0.00136 -81.2

0.5 0.5 100 2500 0.00951 0.01036 8.9 0.00154 -83.8

0.5 0.5 100 3000 0.00980 0.01045 6.6 0.00148 -84.9

0.5 0.5 100 4000 0.01029 0.01024 -0.5 0.00140 -86.4

0.5 0.5 100 5000 0.01059 0.00998 -5.8 0.00136 -87.2

0.2 0.8 100 2500 0.01400 0.01527 9.1 0.00154 -89.0

0.2 0.8 100 3000 0.01424 0.01488 4.5 0.00148 -89.6

0.2 0.8 100 4000 0.01463 0.01420 -2.9 0.00140 -90.4

0.2 0.8 100 5000 0.01493 0.01376 -7.8Sum Errors: 14.1 -1227

Max. Abs. Error: 10.5 90.4AE, % 0.9 -81.8

AAE, % 6.1 81.8

Note that the non-physical behavior of the pure H2S water content at high pressures would still have an effect on acid gas mixtures at elevated pressures. Over mixtures of 10/90, 20/80, 50/50 and 80/20, an average declination error of –5.8% was noticed, which is relatively insignificant.

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CONCLUSIONS

To design a sour gas injection scheme, water content, phase behavior and physical properties of the acid gas mixture over the range of operating temperatures and pressures of interest are required. Existing correlations and models cannot be applied to pure and/or acid gas mixtures. AQUAlibriumTM and VMGSimTM, which perform rigorous thermodynamic flash calculations, are two of the best models that can be utilized for acid gas injection applications.

A new, simpler and theoretically-based model that predicts equilibrium water content over a temperature range of 32°F to 212°F (0°C to 100°C) and a pressure range of 14.7 psia to 2,000 psia (101 kPa to 14,000 kPa) for pure acid gas components and acid gas mixtures that contain up to 5 mol % hydrocarbons has been developed. This new model provides a quantitative estimate of changes in the equilibrium water content of acid gas mixtures. Compared with the available experimental data set (159 points) the new model results in an absolute average error (AAE) of 14% compared to 15% for AQUAlibriumTM and 14% for VMGSimTM. For 16 water content data points for different acid gas mixtures at 100 °F and pressures from 2,500 to 5,000 psia, and where no experimental data exist, the new model extrapolates very well into high pressure regions with a maximum error of 18% and an average absolute error of 8% compared to AQUAlibriumTM, and with a maximum error of 11% and an average absolute error of 6% compared to VMGSimTM.

ACKNOWLEDGMENT

The authors would like to thank Paul Davis from Alberta Sulphur Research Ltd. (ASRL), Edward Wichert from Sogapro Engineering Ltd. and John Carroll from Gas Liquids Engineering Ltd. for sharing their valuable input.

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REFERENCES

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3. Alami, I. A "Water Content of High Pressure Acid Gas: A Mathematical Model" Diss. University of Calgary, 2004.

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18. Selleck, F., L. T. Carmichael, and B. H. Sage. "Phase Behavior in the Hydrogen Sulfide-Water System." Industrial & Engineering Chemistry Research 44 (1952): 2219-26.

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19. Sharma, S. C. "Equilibrium Water Content of Gaseous Mixtures." Diss. University of Oklahoma, 1969.

20. Sharma, S. C. and J. M. Campbell. "Predict natural-gas water content with total gas usage." Oil and Gas Journal 67.31 (1969): 136-37.

21. Wichert, Gordon C. and Edward Wichert. "New charts provide accurate estimations for water content of sour natural gas." Oil and Gas Journal 101.41 (2003): 64-66.

22. Wiebe, R. and V. L. Gaddy. "Vapor Phase Composition of Carbon Dioxide-Water Mixtures at Various Temperatures and Pressures to 700 Atmospheres." J Am.Chem.Soc. 63 (1941): 475-77.

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Page 21: Alami Svrcek Monnery Water Content Paper Rev 3.3

Nomenclature

partial pressure of component “i”

vapor pressure of component “i”

liquid mole fraction of component “i”

system pressure

mole fraction of component “i” in the vapor phase

water content of the hydrocarbon portion of the gas from McKetta-Wehe chart

effective water content of CO2

effective water content of H2S

mole fractions of hydrocarbon, CO2 and H2S respectively.

water content of the sour gas

correction factor

vapor pressure of water at the system temperature

fugacity of water at its vapor pressure and system temperature

fugacity of water at the system pressure and temperature

mole fraction of the water in the gas

compressibility factor of mixture

fugacity of the total gas mixture at the system pressure and temperature

fugacity coefficient of water vapor in natural gas mixture, psia

water liquid molar volume, ft3/lbmol

gas constant, 10.732 (psia*ft3)/(°R*lbmol)

fugacity coefficient of water at its vapor pressure, , and system temperature T

Poynting Correction

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