- Email: [email protected]
Fluid behavior of gas condensate system with water vapor
Accepted Manuscript Fluid behavior of gas condensate system with water vapor Zhouhua Wang, Hanmin Tu, Ping Guo, Fanhua Zeng, Tingyi Sang, Zidun Wang PII:
S0378-3812(17)30039-0
DOI:
10.1016/j.fluid.2017.01.018
Reference:
FLUID 11387
To appear in:
Fluid Phase Equilibria
Received Date: 26 October 2016 Revised Date:
19 January 2017
Accepted Date: 19 January 2017
Please cite this article as: Z. Wang, H. Tu, P. Guo, F. Zeng, T. Sang, Z. Wang, Fluid behavior of gas condensate system with water vapor, Fluid Phase Equilibria (2017), doi: 10.1016/j.fluid.2017.01.018. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
ACCEPTED MANUSCRIPT
Fluid behavior of gas condensate system with water vapor Zhouhua Wanga, Hanmin Tua, Ping Guo a*, Fanhua Zengb, Tingyi Sangc, Zidun Wanga a
RI PT
State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, China b Petroleum Systems Engineering, Faculty of Engineering and Applied Science, University of Regina, Regina, Saskatchewan, Canada c Tuha Oilfield Company, PetroChina Company Limited, Hami, Xinjiang, China
SC
Abstract
For most gas condensate reservoirs, a high water cut and near-wellbore retrograde
M AN U
condensate pollution are the main problems encountered by engineers. Thus, a good understanding of the influence of water vapor and the complex phenomenon of a near wellbore region on the phase behavior of gas condensate is critical to forecast the performance of reservoir fluids and guide the exploitation of gas condensate
TE D
reservoirs. In the present work, constant composition expansion (CCE) and constant volume depletion (CVD) measurements are performed to determine the phase behavior of gas condensate samples with and without water vapor. Our experimental
EP
results demonstrate that water vapor not only increases the dew point pressure, but it also influences other gas-related properties. Furthermore, several equations are
AC C
applied to predict the solubilities and gas-related properties. As the predictions are compared to each other, it is obvious that the cubic-plus-association (CPA) equation
of state (EOS) performs very well in all properties with a test fitting interaction parameter. A good agreement between the experimental data and predictions is observed.
1
ACCEPTED MANUSCRIPT
Keywords: Gas condensate reservoir; fluid behavior; gas phase properties; water vapor; equation of state
RI PT
1. Introduction Gas condensate reservoirs, in which value has been found through industrial exploitation, perform an important function in natural gas reservoirs. Knowledge of
SC
the phase behavior of gas condensate reservoirs, which varies according to the gas/oil ratio, is crucial for predicting reservoir performance and future processing needs.
M AN U
Experimental measurements are usually of primary importance in determining these properties. Nowadays, researchers worldwide have studied phase behavior extensively by analyzing the composition of the reservoir fluid and performing CCE and CVD tests [1-6].
TE D
It is well known that hydrocarbons and water coexist in most gas condensate reservoirs, and the existence of water could promote highly complex phase behavior
EP
in these reservoirs. However, most reported phase behavior researches for gas condensate ignore the influence of water. Therefore, experimental devices and
AC C
processes do not include the special treatment of water, and researchers haven’t established theoretical model. The influence of water vapor on gas related properties is a difficult research theme, but it has practical and theoretical value, and there is a large deviation in the findings of gas condensate studies without consideration of the effects of water. A few studies have reported about the effect of water on the phase behavior of gas condensate reservoirs [7-8]. The current data only reveal that two incipient phases (a 2
ACCEPTED MANUSCRIPT
hydrocarbon gas phase and an aqueous phase) exist, instead of a single gas phase. Lindeloff and Michelsen [9] presented an algorithm to determine the phase diagram of
RI PT
a gas condensate/water system. Bang et al. [10] performed CCE and CVD tests over a wide temperature range for several mixtures. Kokal et al. [8, 11] used the same experimental method for gas condensate samples from the Khuff reservoir in Ghawar.
SC
They found that, owing to the mass transfer between the gas and water contacting
system, the maximum amount of liquid dropout showed an increase of approximately
M AN U
20% to 25% at 126.7 ℃. Thus, the related properties of gas condensate (e.g., dew point pressure, relative volume, and liquid yields) are strongly influenced by the presence of water.
Over the past decades, though different thermodynamic models have been
TE D
evaluated by traditional equations of state such as PR, PR78, SRK, SRK-HV, UNIQUAC [12], and UNIFAC [13], none of the above conventional equations explicitly takes into account the interactions between molecules, which involve
EP
associating compounds. Nowadays, many attempts have been made in the development of an EOS that is considered a system containing associating compounds
AC C
[14-19]. The cubic-plus-association (CPA) equation of state [20-21] is the most recent EOS that combines the physical part of the SRK EOS [22] with the association term based on the Statistical Association Fluid Theory (SAFT) [16, 23]. The CPA EOS has been widely used to pure components and Vapor-Liquid equilibrium, Liquid-Liquid equilibrium
and
Solid-Liquid
equilibrium
for
associating-associating
and
associating-inert systems [20-21, 24-28]. For many petrochemical processes, the
3
ACCEPTED MANUSCRIPT
description of the water/hydrocarbon system is a challenging aspect of development. Over a wide range of temperatures and pressures, systems of water exhibit the limited
RI PT
miscibility of hydrocarbons [29-31]. The prediction of the CPA EOS shows a good correlation with the experimental data on water/hydrocarbon systems [29-30, 33-35].
In this work, we performed CCE and CVD tests on a gas condensate system with
SC
water vapor to investigate the influence of water vapor on the phase behavior of
condensate fluid and the gas phase. Similar experiments for a water free gas
M AN U
condensate sample were performed for comparison. In addition, several equations of state (PR, PR78, SRK, SRK-HV, and CPA-SRK) were employed to demonstrate the solubility data and the prediction of gas-related properties. 2. Experimental Apparatus and Procedures
TE D
2.1 Experimental apparatus
To perform the pressure/volume/temperature (PVT) experiments, we set up a
EP
high-pressure and high-temperature laboratory. A schematic of the experimental setup is presented in Fig. 1. A mercury-free DBR (Donald B. Robinson Company) PVT cell
AC C
was used to study the phase behavior properties of the fluid samples. A transparent glass cylinder cell with a volume of approximately 400 mL and a maximum working pressure of 70 MPa at 473K was one of the most important parts of the experimental system. The test fluid sample was placed in the cell by pushing a Ruska pump connected to the top of the cell. The volume of the injected sample was monitored by a cathetometer. A magnetic mixer arranged on the end cap of the cell was utilized to reduce the time required to reach equilibrium during operation. To ensure the 4
ACCEPTED MANUSCRIPT
accuracy of the measurement, the volume of the PVT cell, the temperature readers, and the pressure transducers were calibrated frequently before the start of the
RI PT
experiment (measured quantities temperature±0.1℃, pressure±0.05MPa, volume±
Intermediate Container
Chromatograph
Hydrometer
Separator
Gasometer
Separator of Ground
M AN U
Viscometer
SC
0.1cm3).
PVT cell
Automatic Pump
Fig. 1. Schematic diagram of the experimental apparatus [36].
TE D
2.2 Phase equilibrium measurement.
2.2.1 Water free gas condensate measurements Phase equilibrium measurements usually include CCE and CVD experiments. In
EP
this study, the CCE test consisted of varying the pressure and measuring the resulting volume of the single phase fluid above saturation pressure. Measuring the volumes of
AC C
the vapor and liquid phases below the saturation pressure was done first while trying to determine the dew point pressure. The dew point pressure was determined by reducing the system pressure in small
increments until tiny liquid droplets emerge. To confirm the accuracy of the dew point pressure, great attention and an increased amount of concentration were required to perform three repetitive tests by increasing and decreasing the pressure around the
5
ACCEPTED MANUSCRIPT
dew point. When the pressure of PVT cell was lowered to the dew point pressure, both the amount and the size of droplets increased with the decrease of pressure. This
RI PT
phenomenon continued until a new gas–liquid equilibrium was reached at the current pressure, and the above process would have been repeated until the pressure was reduced to approximately 5 MPa.
SC
After the CCE test, a CVD test was performed continuously to assess the
recovery of the gas and liquid phase at different depletion pressures. This experiment
M AN U
consists of starting with a volume of fluid at its saturation pressure, which again defines the PVT cell or control volume for the experiment. Then the pressure is dropped by 3 to 4 MPa or so, whereupon the fluid becomes two phases and expands in volume. Any excess volume over and above the cell is removed by taking off the
TE D
gas, which is analyzed compositionally and volumetrically, as well as noting the number of moles through a valve on the top of the PVT cell. Furthermore, the percentage of liquid in the remaining fluid, the cell volume, defines the liquid
EP
saturation.
After the above two tests, the gas condensate sample was flashed into a container
AC C
at standard conditions (0.1 MPa and 289.15 K). The separated gas was collected in a gasometer and its composition was analyzed by a chromatograph. The properties of the condensate liquid were also measured. The gas condensate ratio was then calculated based on the amounts of gas and condensate collected.
6
ACCEPTED MANUSCRIPT
2.2.2 Gas condensate with water vapor system The pressure/volume/temperature experiments for a gas condensate sample with
RI PT
gaseous water were initiated by adding a certain amount of water free gas condensate sample prepared beforehand and an excess amount of aqueous phase to the sample
container. In order to mix well, the container was heated to reservoir temperature and
SC
rocked constantly. After about 48 hours, the gas-water equilibrium was regarded as achieved. The gas phase was saturated entirely with water vapor and the aqueous
M AN U
phase was completely dissolved with gases. Then the superfluous water was discharged through a valve at the bottom of the sample container to ensure that only a gas phase existed in the container. The prepared gas sample was then transported into the PVT cell. CCE and CVD tests were performed via similar procedures described
TE D
earlier for the water free gas condensate sample.
In this work, the content of water vapor in the gas phase was determined based on the method described in our previous work (Che et al., 2008). An increased amount of
EP
concentration was required to ensure the accuracy of the test. Thereafter two sets of
AC C
flashes were conducted. The first flash was with the prepared gas condensate sample containing water vapor. In flashing, the outlet fluid was frozen by liquid nitrogen in a separation vessel and three phases were observed gradually: (a) a gas phase, (b) a hydrocarbon liquid phase, and (c) an aqueous phase. The gas was collected and analyzed, the properties of the hydrocarbon liquid were measured, and the amount of water was recorded. The GCR was then calculated.
7
ACCEPTED MANUSCRIPT
The second flash was performed on the aqueous phase discharged from the container earlier. This step was required to obtain the composition of hydrocarbons
RI PT
dissolved into the aqueous phase. 3. Results and discussion 3.1 The properties of samples
SC
The gas condensate samples used in this work were collected from a gas
M AN U
condensate reservoir in southwest China. The reservoir pressure and temperature for this reservoir are 34 MPa and 351.15K, respectively. The experimental composition analysis results are provided in Table 1. The first and second columns show the separator gas and oil compositions analyzed by a gas chromatograph. The third column shows the water free gas condensate compositions obtained by recombining
TE D
the separator gas and oil phase (Sample 1) according to the GCR. The fourth column shows the compositions of the recombined gas condensate sample with the water
EP
vapor (Sample 2) obtained by recombining of a certain amount of water free gas condensate sample and an excess mount of water. The last column shows the
AC C
compositions of the aqueous phase that was discharged from the sample container, and this aqueous phase was analyzed by a gas chromatograph. The separated GCR is 2879 m3/m3 under the conditions of 4.8 MPa and 289.15K, and the total GCR of the reservoir fluid is 3001 m3/m3 (calculated at standard conditions). A reduction in GCR
from 3001 m3/m3 for Sample 1 to 2879 m3/ m3 for Sample 2 was noted. This reduction is attributed to the dissolution of light components (mainly CH4, C2H6, and CO2) in the aqueous phase and the volatilization of water in the gas phase. 8
ACCEPTED MANUSCRIPT
Table 1. The compositions of samples. Sample 2 Gas Condensate with Water Vapor (mol %)
Component
abbreviations
Separator Gas (mol %)
Nitrogen
N2
0.20
0.00
1.47
CO2
1.42
0.00
1.56
Methane
C1
88.17
0.05
80.93
Ethane
C2
6.70
0.02
5.62
Propane
C3
1.98
0.07
Isobutene
iC4
0.37
Butane
nC4
0.41
2-Methlbutane
iC5
0.14
Pentane
nC5
0.12
Hexane
C6
0.49
Heptane
C7
0.00
Octane
C8
0.00
Nonane
C9
0.00
Deane
C10
Undecane Water GCR
Aqueous Phase (mol %)
0.0009
1.51
0.0082
80.11
0.2130
5.48
0.0096
3.88
3.87
0.0016
0.18
1.10
1.08
0.0000
0.14
1.28
1.28
0.0000
0.50
0.32
0.32
0.0000
0.17
0.20
0.20
0.0000
5.59
0.43
0.43
0.0000
4.57
0.17
0.18
0.0000
7.11
0.36
0.37
0.0000
5.72
0.35
0.39
0.0000
0.00
9.26
0.44
0.49
0.0000
C11
0.00
67.52
1.92
2.18
0.0000
H2O
0.00
0.00
0.00
SC
1.42
TE D
dioxide
Water Free Gas Condensate (mol %)
M AN U
Carbon
Separator Oil (mol %)
RI PT
Sample 1
3
0.67 3
3001m /m
3
99.7667 3
2879 m /m
EP
Table 2 shows the percentage of average absolution deviation (AAD calculated
AC C
by the Eq.1) between the experimental and calculated values in the solubility of water in the vapor phases (Ywater) and in the solubility of hydrocarbons in the aqueous phase
(XHC). The table also shows the amount of water in the aqueous (Xwater) phase by using different equations of state where the AADs for solubility are estimated and summarized. AAD(%) =
xexp,i − xcal ,i 1 NP abs( ) × 100 ∑ NP i =1 xexp,i
9
(1)
ACCEPTED MANUSCRIPT
To improve the prediction result, the interaction parameters were adjusted by minimizing the function (Smith and Srivastava, 1986) defined by Eq.2, and this
sat Pcalsat − Pexp Q =∑ P sat i =1 exp NP
2
NP V liq − V liq exp cal + ∑ liq i i =1 Vexp
2
i
RI PT
equation is solved using the least square method: (2)
Where NP is the number of experimental data points, Psat is the vapor pressure, and
SC
V liq is the saturated liquid volume. For the vapor-liquid equilibrium (VLE) calculation,
CPA pure components parameters for associating the compounds and hydrocarbons
M AN U
used in this work were obtained from the literature [29, 39], and the water was modeled as a 4C scheme [39]. Table 3 only presents the interaction parameters of water-hydrocarbon for the SRK-HV and SRK-CPA EOSs. The calculation procedure of other equations of state is similar to the above two equations of state.
TE D
A summary of the VLE results shown in Table 2 demonstrate that, in most of the cases, the CPA EOS gives a relatively accurate prediction of the water content in the
EP
vapor phase with only 1.88% AAD at the temperature of 351.15K followed by the SRK-HV equation with 5.03 AAD%. Other conventional equations of state have a
AC C
significant deviation in prediction solubilities. In the following calculation process, only the above two correction equations are applied. For the non-polar substance system, the CPA-SRK EOS can be simplified as the SRK EOS. Table 2. Percentage average absolute deviation (% AAD) between experimental water solubilities and calculated values from different equation of states. EOS
AAD in Xwater (%)
AAD in XHC (%)
AAD in Ywater(%)
PR
0.18
42.92
133.04
PR78
0.18
41.49
132.78
10
ACCEPTED MANUSCRIPT
SRK
0.19
45.59
136.98
SRK-HV
0.18
22.06
5.03
CPA-SRK
0.03
9.01
1.88
Table 3. The binary interaction parameters of SRK-HV and SRK-CPA equations of state. Component
Binary Interaction Parameters SRK-HV SRK-CPA α H 2O − j k H 2O − j
RI PT
Binary Interaction Parameters SRK-HV SRK-CPA α H 2O − j k H 2O − j 0.0573
-0.0481
nC5
-0.0033
-0.0249
CO2
0.0020
0.0265
C6
-0.0060
0.0080
C1
-1.026
0.0073
C7
-0.0007
0.0094
C2
-0.0214
0.0043
C8
0.0014
0.0126
C3
-0.0363
0.0079
C9
0.0048
0.0301
iC4
-0.0163
0.0043
C10
0.0103
0.0319
nC4
0.0057
0.0321
iC5
-0.0054
0.0207
M AN U
N2
SC
Component
C11
-2.9959
0.0084
3.2 The influence of water vapor on phase behavior
Two gas mixtures are shown in Table 1 with and without water vapor. The
TE D
mixtures were used to study the effect of water vapor on the phase behavior properties of selected gas condensate reservoirs. The procedure of Pedersen and Milter [7] is utilized to characterize the above two samples and the characterized results are
EP
presented in Table 4. By the calculation method proposed by Lindeloff and Michelsen
AC C
[9], the SRK-HV was applied to estimate the phase envelope in this work. As shown in Fig. 2, the phase envelope of the water free gas condensate sample is surrounded by the phase envelope of the water vapor sample. Moreover, the phase envelope gives the critical temperature and pressure of 178.16 K and 5.91 MPa for the water free gas condensate sample and 180 K and 6.83 MPa for the water vapor sample. In contrast to the phase diagram of water free gas condensate sample, the phase envelope of the water vapor sample calculated by the method provided by Lindeloff and Michelsen [9] 11
ACCEPTED MANUSCRIPT
divided the phase diagram into four regions, as shown in Fig. 2. Region A represents the single gas phase region; Region B represents the gas-oil two-phase region; Region
RI PT
C represents the gas-water two-phase region; and Region D represents the gas-water-oil three-phase region. The symbol “2-Aq” means the dew point line that separates the single and two-phase regions and sets the aqueous phase as the initial
SC
phase. The symbol “3-Aq” means the phase envelope line that separates the two and three phase regions and sets the aqueous phase as the initial phase. In the same way,
M AN U
for the calculation of the initial hydrocarbon phase, 2-HC and 3-HC have the same meaning.
Under the temperature and pressure of a gas reservoir, the initial state of the sample with water vapor is a single gas phase. After the pressure was lowered to
TE D
below the dew point pressure, two phases emerged gradually: (a) a hydrocarbon gas phase and (b) a hydrocarbon liquid phase. This indicates that the liquid dropout is solely composed of condensate oil.
Table 4. Characterized gas condensate mixtures.
EP
Sample 1
AC C
Component N2 CO2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9
Mol (%) 1.470 1.560 80.93 5.620 3.880 1.100 1.280 0.320 0.20 0.430 0.170 0.360 0.350 12
Sample 2 Component N2 CO2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9
Mol (%) 1.420 1.510 80.110 5.480 3.870 1.080 1.280 0.320 0.200 0.430 0.180 0.370 0.389
ACCEPTED MANUSCRIPT
ρC19-C49 MC19-C49
0.8013 298
C10 C11 C12 C13 C14 C15 C16 C17-C19 C20-C51 H2O ρC20-C51 MC20-C51
35
A
Pressure(MPa)
25 20 15
M AN U
C
30
0.490 0.556 0.389 0.297 0.258 0.157 0.146 0.198 0.183 0.669 0.8015 315
RI PT
0.440 0.529 0.383 0.278 0.201 0.146 0.105 0.132 0.145
SC
C10 C11 C12 C13 C14 C15 C16 C17-C18 C19-C49
B
10
D
0 150
TE D
5
200
250
300
350
400
450
500
550
Temperature(K)
EP
water free sample 3-Aq 3-HC Cp of water free sample
B—gas-oil two phase region D—gas-water-oil three phase region
AC C
A—single gas phase region C—gas-water three phase greion
2-Aq 2-HC The condition of reservoir Cp of water vapor sample
Fig. 2. The phase envelope for both gas condensate samples
The CCE test results suggest that the presence of water vapor not only
significantly increases the dew point pressure, but it also raises the amount of liquid dropout, nevertheless there seems to be no obvious difference in the relative volumes obtained for both samples (all relative volumes are the ratio of gas volumes at different pressures and the gas volume under dew point pressure, see Figs. 3–5 and
13
ACCEPTED MANUSCRIPT
Table 5). The measured results demonstrated that the presence of water vapor increases the dew point pressure by almost 1 MPa, and this can be also seen in the
RI PT
calculated results shown in Fig. 2, where the values of Sample 1 and Sample 2 are 30.34 MPa and 31.12 MPa, respectively. Due to the large critical temperature and the
critical pressure of water, here, water can be considered as a heavy component. This
SC
designation makes the content of light components in the mixture decrease and the
proportion of the heavy components increase, and thus it increases the dew point
M AN U
pressure of the system. 10
SRK SRK-HV
8
6
4
2
0 0
TE D
Reletivw volume
Experiment
7
14
21
28
EP
Pressure(MPa)
AC C
Fig. 3. The relative volume of the water free gas condensate sample
14
35
ACCEPTED MANUSCRIPT
10
CPA-SRK SRK-HV
8
Reletive volume
Experiment
4
2
0 7
14
21
28
35
SC
0
RI PT
6
Pressure(MPa)
M AN U
Fig. 4. The relative volume of the water vapor gas condensate sample 10
Experiment with water vapor sample Experiment with free water vapor sample
6
4
2
0 0
TE D
Reletive volume
8
7
14
21
28
35
EP
Pressure(MPa)
AC C
Fig. 5. The comparison of the experimental relative volume between the two gas condensate samples Table 5. The deviation between the calculated results and the experimental data Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
3.90
SRK-CPA
0.69
SRK-HV
1.48
SRK-HV
2.51
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 4.2% calculated by SRK, and 1.7% by SRK-HV while that of water vapor sample is 0.73 % and 2.68% by the SRK-CPA and SRK-HV, respectively.
15
ACCEPTED MANUSCRIPT
For both samples, the curves between the retrograde condensate saturation and the pressure appear smooth, and these data show a trend of a quick increase that
RI PT
reached a maximum and subsequently reduce with a further decrease in pressure (see Figs. 6–8). Also, it can be seen in Fig. 8 that, owing to the presence of water vapor,
the curve of the gas condensate with the water vapor sample moves entirely toward
SC
the pressure expansion side of the X-axis in comparison with the curve of the water free gas condensate sample. This phenomenon caused an approximately 7.12–8.51%
M AN U
increase in the maximum liquid dropout and 18–20MPa growth in the maximum retrograde condensate pressure. This increasing trend is mainly caused by the interphase mass transfer between the gas and aqueous phase, leading to an increase in the mole fraction of the water vapor and a decrease in the mole fraction of light
TE D
hydrocarbons in the gas phase. Thus, the presence of water will accelerate the precipitation of the heavy components, and more liquid will be released. Because of this, the retrograde condensate saturation curve of the water vapor sample is above the
8
AC C
Retrograde condensate saturation（%）
EP
curve of the water free sample.
6
4
SRK
2
SRK-HV Experiment 0 0
7
14
21
Pressure(MPa)
16
28
35
ACCEPTED MANUSCRIPT
Fig. 6. The retrograde condensate saturation of water free gas condensate sample for CCE test
RI PT
8
6
4 CPA-SRK SRK-HV
2
Experiment
SC
Retrograde condensate saturation(%)
10
0 0
7
14
21
28
M AN U
Pressure(MPa)
35
Fig. 7. The retrograde condensate saturation of the water vapor gas condensate sample for CCE test
8
TE D
6
4
Experiment with water vapor sample
2
Experiment with free water vapor sample
0
EP
Retrograde condensate saturation (%)
10
0
7
14
21
28
35
Pressure(MPa)
AC C
Fig. 8. The comparison of the retrograde condensate saturation between the two gas condensate samples for CCE test Table 6. The deviation between the calculated results and the experimental data on the retrograde condensate saturation of the CCE test Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
7.50
SRK-CPA
2.46
SRK-HV
4.59
SRK-HV
9.86
17
ACCEPTED MANUSCRIPT
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 7.79% calculated by SRK, and 5.06% by SRK-HV while that of water vapor sample is 2.66 % and 10.08% by the SRK-CPA and SRK-HV, respectively.
Figs. 9–11 provide the retrograde condensate saturation results for the CVD test
RI PT
where the variation of the curves is similar to that observed in the CCE test and the
maximum retrograde condensate saturation increases from 8.52% for the water free sample to 9.6% for the water vapor sample. Although the curves show the same
SC
regularity, in general, the values of CCE test results are slightly smaller than the
8
6
4 SRK
2
TE D
Retrograde condensate saturation (%)
10
M AN U
values of the CVD test.
SRK-HV
Experiment
0 0
7
14
21
28
35
Pressure(MPa)
10
AC C
Retrograde condensate saturation(%)
EP
Fig. 9. The retrograde condensate saturation of the water free gas condensate sample for CVD test
8
6
4
2
CPA-SRK SRK-HV Experiment
0 0
7
14
21
Pressure(MPa)
18
28
35
ACCEPTED MANUSCRIPT
Fig. 10. The retrograde condensate saturation of the water vapor gas condensate sample for CVD test
RI PT
8
6
4
2
Experiment with free water vapor sample Experiment with water vapor sample
0 0
7
14
21
SC
Retrograde condensate saturation (%)
10
28
M AN U
Pressure(MPa)
35
Fig. 11. The comparison of the retrograde condensate saturation between the two gas condensate samples for CVD test Table 7. The deviation between the calculated results and the experimental data on the retrograde condensate saturation of the CVD test Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
AAD (%)
EOS
AAD (%)
SRK
16.49
SRK-CPA
1.44
SRK-HV
4.59
SRK-HV
TE D
EOS
4.56
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 16.52% calculated by SRK, and 4.66% by SRK-HV while that of water vapor sample is
EP
1.45 % and 4.28% by the SRK-CPA and SRK-HV, respectively.
For engineers who are most concerned about the cumulative recovery, all
AC C
cumulative recoveries shown in Figs. 12–17 are defined as cumulative amounts of the gas or liquid phases at different pressures relative to the total amounts of the gas or liquid phases. The ultimate recoveries of the gas phase (see Figs. 12–14) are 82.34% and 92.51%, and the values of the liquid phase (see Figs. 15–17) are 17.59 % and 16.45% for the water free sample and water vapor sample, respectively. Studies have led to the conclusion that there is relatively smaller difference in the gas cumulative recoveries while there is an intersection point of the liquid recovery curve. The values 19
ACCEPTED MANUSCRIPT
of the water vapor sample are slightly larger on the right side of the intersection point, and an opposing case is observed on the left side of the intersection point. This can be
RI PT
explained by the fact that the rise of the dew point pressure leads to the condensation of the heavy component in advance; thus causing a significant loss in the condensate liquid. 90 75
SC
SRK-HV
Experiment
60 45 30 15 0 0
7
M AN U
Cumulative recovery (%)
SRK
14
21
28
35
Pressure(MPa)
80 60
CPA-SRK SRK-HV Experiment
EP
Cumulative recovery(%)
100
TE D
Fig. 12. The cumulative recovery of the gas phase of the water free gas condensate sample
40
AC C
20 0
0
7
14
21
28
35
Pressure(MPa)
Fig. 13. The cumulative recovery of the gas phase of the water vapor gas condensate sample
20
ACCEPTED MANUSCRIPT
90
Experiment with free water vapor sample Experiment with water vapor sample
60 45
RI PT
Cumulative recovery (%)
75
30 15 0 0
7
14
21
28
35
Pressure(MPa)
condensate samples
SC
Fig. 14. The comparison of the cumulative recovery of the gas phase between the two gas
M AN U
Table 8. The deviation between the calculated results and the experimental data on the cumulative recovery curves of gas phase Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
19.41
SRK-CPA
4.67
SRK-HV
7.03
SRK-HV
5.39
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of
TE D
water free sample is 17.78% calculated by SRK, and 7.11% by SRK-HV while that of water vapor sample is 4.72% and 5.51% by the SRK-CPA and SRK-HV, respectively.
16
EP
Cumulative recovery (%)
20
AC C
12
8
4
SRK SRK-HV Experiment
0
0
7
14
21
Pressure (MPa)
21
28
35
ACCEPTED MANUSCRIPT
Fig. 15. The cumulative recovery of the liquid phase of the water free gas condensate sample 20
Cumulative recovery(%)
16
RI PT
12
8 CPA-SRK
4
SRK-HV
0
7
14
21
Pressure(MPa)
SC
Experiment
0
28
35
M AN U
Fig. 16. The cumulative recovery of the liquid phase of the water vapor gas condensate sample
16
12
8
TE D
Cumulative recovery (%)
20
Experiment with free water sample
4
Experiment with water vapor sample
0
7
14
EP
0
21
28
35
Pressure(MPa)
AC C
Fig. 17. The comparison of the cumulative recovery of the liquid phase between the two gas condensate samples Table 9. The deviation between the calculated results and the experimental data on the cumulative recovery curves of liquid phase Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
12.22
SRK-CPA
3.27
SRK-HV
8.11
SRK-HV
6.16
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 12.21% calculated by SRK, and 8.12% by SRK-HV while that of water vapor sample is 3.15% and 5.76% by the SRK-CPA and SRK-HV, respectively.
22
ACCEPTED MANUSCRIPT
It was mentioned that the SRK-CPA and SRK-HV equation of states are typically applied, which yield acceptable errors in the estimation of gas and liquid related
RI PT
properties seen in Tables 5–9. It is not hard to see that the CPA-SRK corrects the experimental results with a smaller error. 4. Conclusions
SC
In this work, equilibrium CCE and CVD tests were performed on gas condensate samples with and without water vapor. Although the solubility of water in the gas
M AN U
phase at reservoir conditions is limited, the influence of the water on the gas related properties of the reservoir fluid is quite considerable. This study shows that very good results can be predicted by the CPA-SRK EOS. The following conclusions can be drawn based on the tests conducted:
TE D
The presence of water vapor not only increases the dew point pressure, but it also leads to a change in other gas-related properties of gas condensate reservoirs (e.g. the
EP
P/V relationship, the amount of liquid dropout, and the recoveries). Some properties, especially the liquid dropout of the curves, move wholly toward the pressure
AC C
expansion side. This indicates that there is a significant deviation when the presence of water is ignored.
As known from the simulation results of the water vapor sample, there are two
cases: (a) initially saturated water and (b) oversaturated water. When the pressure decreases below the dew point pressure, the condensate liquid of the initially saturated water consists solely of hydrocarbons in liquid phase while the condensate of
23
ACCEPTED MANUSCRIPT
oversaturated water includes not only the hydrocarbons liquid, but also the aqueous phase.
RI PT
The CPA EOS has been applied to predict the solubility and gas-related properties of gas condensate reservoirs. A good agreement between experimental data and
predictions was obtained, demonstrating that this equation of state is suitable for
AC C
EP
TE D
M AN U
SC
multicomponent mixtures containing water and hydrocarbons.
24
ACCEPTED MANUSCRIPT
Acknowledgment
RI PT
This work was supported by the National Natural Science Foundation of China (No. 51374179, “Theory and molecular dynamics study on CO2-crude oil non-equilibrium
diffusion considering capillary pressure and adsorption”) and the “National
SC
Scholarship in the Western Region Talent Training Special Project Funding (No. 201508515157).”
M AN U
References
[1] M.E. Aily, M.H.M. Khalil, S.M. Desouky, M. H. Batanoni, M.R.M. Mahmoud. Egypt. J. Pet.22 (2013)129-136.
[2] J.K. Drohm, R.D. Trengrove, W.H. Goldthorpe. Society of Petroleum Engineers, 1988. [3] T.O. Amao, A.M. Amao. Society of Petroleum Engineers, 2014.
[4] T. Ahmed. Third ed., Gulf publishing company, Houston, Texas, 2007. [5] T.H. Ahmed. SPE Reservoir Eng. 3(1986)337-348.
TE D
[6] H.C. Song, Y. Jin. Journal of Qiqihar University, 3(2012)79-82.
[7] K.S. Pedersen, J. Milter. SPE Annual Technical Conference and Exhibition, 2004 [8] K. Sunil, A.D. Mohammad, S. Selim. SPE Reservoir Eval. Eng. 6(2000)294-300. [9] L. Niels, M. L. Michelsen. SPE J.8 (2013)298-303. [10] V.S.S. Bang, G.A. Pope, M.M. Sharma. SPE J.15 (2010)952-962.
EP
[11] S. Kokal. SPE Reservoir Eval. Eng. 6(2003):412-420. [12] T.F. Anderson, J.M. Prausnitz. Ind. Eng. Chem. Process Des. Dev.17 (1978)561-567. [13] P.A. Gupte, R.P. Danner. Ind. Eng. Chem. Res. 26(2002):2036-2042.
AC C
[14] S.H. Huang. M. Radosz. Fluid Phase Equilib.70 (1991)33-54.
[15] I.G.Economou, G.D.Ikonomou, P.Vimalchand, M.D.Donohue.AlChE J.36 (1990) 1851-1864. [16] W.G.Chapman, K.E.Gubbins, G.Jackson, M.Radosz. Ind.Eng.Chem.Res.29 (1990)1709-1721. [17] A. Anderko. Fluid Phase Equilib.65 (1991)89-110. [18] S.J. Suresh, J.R. Elliott. Ind. Eng. Chem. Res.30 (1991)524-532. [19] G.D. Ikonomou, M.D. Donohue. Fluid Phase Equilib.39 (1998)129-159. [20]G.M. Kontogeorgis, E.C.Voutsas, V.Y.Iakovos, D.P.Tassios. Ind.Eng.Chem.Res. 35(1996) 4310-4318.
[21] I.V. Yakoumis, G.M. Kontogeorgis, E.C. Voutsas, D.P.Tassios. Fluid Phase Equilib.130 (1997) 31-47.
25
ACCEPTED MANUSCRIPT
[22] G. Soave. Chem. Eng. Sci. (1972)1197-1203. [23] S.H. Huang. M. Radosz. Fluid Phase Equilib.60 (1990) 81-98. [24] G.M. Kontogeorgis, M.L. Michelsen, G.K. Folas, S.Derawi, N.V.S, E.H.Stenby. Ind. Eng. Chem. Res. (2006)2645-56.
other compounds. CRC Press, 1980. 1527-1538.
RI PT
[25] G.K. Folas, G.M. Kontogeorgis, M.L. Michelsen, E.Stenby. Glucuronidation of drugs and
[26] G.K. Folas, S.O. Derawi, M.L. Michelsen, E.H.Stenby, G.M. Kontogeorgis. Fluid Phase Equilib.228 (2005)121-126.
[27] R.A. Wilsak, S.W. Campbell, G. Thodos. Fluid Phase Equilib.33 (1987)157-171. [28] C. T. Liu, W. T. Lindsay, J. Solution Chem.1 (1972) 45-69.
[30] M. Medeiros. Fluid Phase Equilib. 368(2014)5-13.
SC
[29] M.B.Oliveira, J.A.P. Coutinho, A.J. Queimada. Fluid Phase Equilib.258 (2007)58-66.
[31] M. Zirrahi, H. Hassanzadeh, J. Abedi. Fuel.159 (2015)894-899.
M AN U
[32] M. Medeiros. Fluid Phase Equilib. 392(2015)65-73.
[33] A.J. Queimada, I M. Marrucho, E.H. Stenby, G. Kontogeorgis, C. Miqueu, J.A.P. Coutinho. Ann Oncol.26 (2016)132-135.
[34] F. Masoodiyeh, M.R. Mozdianfard,J. Karimi-Sabet. Korean J. Chem. Eng.30 (2013)201-212. [35] M. Hajiw, A. Chapoy, C. Coquelet. Can. J. Chem. Eng.93 (2015):432–442. [36] X. Bian, Z. Du, Y. Tang, J.Du.J.Petrol.Sci.Eng.82 (2012)38-43.
[37] J. Che, P. Guo, J. Fan, J. Du. Natural Gas Exploration & Development. 31(2008)44-48.
TE D
[38] D.S. Buford, S. Rakesh. Elsevier, 1986.
[39] L.C.D. Santos, S.S. Abunahman, F.W. Tavares, V. R. R. Ahón, G. Kontogeorgis. Ind. Eng. Chem. Res.54 (2015)6812-6824.
[40] M.J. Huron, J. Vidal, Fluid Phase Equilib.3 (1979)255–271.
AC C
EP
[41] R.L. Scott. J. Chem. Phys. 25(1956)193-205.
26
ACCEPTED MANUSCRIPT
1) Investigate the effect of water vapor on condensate gas fluid 2) Test the solubility of water in gas condensate fluid under reservoir condition.
RI PT
3) Analyze the effect of water on hydrocarbons phase behavior experimentally. 4) Suggest CPA EOS as the best choice for calculating the properties of aqueous
AC C
EP
TE D
M AN U
SC
fluids.
S0378-3812(17)30039-0
DOI:
10.1016/j.fluid.2017.01.018
Reference:
FLUID 11387
To appear in:
Fluid Phase Equilibria
Received Date: 26 October 2016 Revised Date:
19 January 2017
Accepted Date: 19 January 2017
Please cite this article as: Z. Wang, H. Tu, P. Guo, F. Zeng, T. Sang, Z. Wang, Fluid behavior of gas condensate system with water vapor, Fluid Phase Equilibria (2017), doi: 10.1016/j.fluid.2017.01.018. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.
ACCEPTED MANUSCRIPT
Fluid behavior of gas condensate system with water vapor Zhouhua Wanga, Hanmin Tua, Ping Guo a*, Fanhua Zengb, Tingyi Sangc, Zidun Wanga a
RI PT
State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu, China b Petroleum Systems Engineering, Faculty of Engineering and Applied Science, University of Regina, Regina, Saskatchewan, Canada c Tuha Oilfield Company, PetroChina Company Limited, Hami, Xinjiang, China
SC
Abstract
For most gas condensate reservoirs, a high water cut and near-wellbore retrograde
M AN U
condensate pollution are the main problems encountered by engineers. Thus, a good understanding of the influence of water vapor and the complex phenomenon of a near wellbore region on the phase behavior of gas condensate is critical to forecast the performance of reservoir fluids and guide the exploitation of gas condensate
TE D
reservoirs. In the present work, constant composition expansion (CCE) and constant volume depletion (CVD) measurements are performed to determine the phase behavior of gas condensate samples with and without water vapor. Our experimental
EP
results demonstrate that water vapor not only increases the dew point pressure, but it also influences other gas-related properties. Furthermore, several equations are
AC C
applied to predict the solubilities and gas-related properties. As the predictions are compared to each other, it is obvious that the cubic-plus-association (CPA) equation
of state (EOS) performs very well in all properties with a test fitting interaction parameter. A good agreement between the experimental data and predictions is observed.
1
ACCEPTED MANUSCRIPT
Keywords: Gas condensate reservoir; fluid behavior; gas phase properties; water vapor; equation of state
RI PT
1. Introduction Gas condensate reservoirs, in which value has been found through industrial exploitation, perform an important function in natural gas reservoirs. Knowledge of
SC
the phase behavior of gas condensate reservoirs, which varies according to the gas/oil ratio, is crucial for predicting reservoir performance and future processing needs.
M AN U
Experimental measurements are usually of primary importance in determining these properties. Nowadays, researchers worldwide have studied phase behavior extensively by analyzing the composition of the reservoir fluid and performing CCE and CVD tests [1-6].
TE D
It is well known that hydrocarbons and water coexist in most gas condensate reservoirs, and the existence of water could promote highly complex phase behavior
EP
in these reservoirs. However, most reported phase behavior researches for gas condensate ignore the influence of water. Therefore, experimental devices and
AC C
processes do not include the special treatment of water, and researchers haven’t established theoretical model. The influence of water vapor on gas related properties is a difficult research theme, but it has practical and theoretical value, and there is a large deviation in the findings of gas condensate studies without consideration of the effects of water. A few studies have reported about the effect of water on the phase behavior of gas condensate reservoirs [7-8]. The current data only reveal that two incipient phases (a 2
ACCEPTED MANUSCRIPT
hydrocarbon gas phase and an aqueous phase) exist, instead of a single gas phase. Lindeloff and Michelsen [9] presented an algorithm to determine the phase diagram of
RI PT
a gas condensate/water system. Bang et al. [10] performed CCE and CVD tests over a wide temperature range for several mixtures. Kokal et al. [8, 11] used the same experimental method for gas condensate samples from the Khuff reservoir in Ghawar.
SC
They found that, owing to the mass transfer between the gas and water contacting
system, the maximum amount of liquid dropout showed an increase of approximately
M AN U
20% to 25% at 126.7 ℃. Thus, the related properties of gas condensate (e.g., dew point pressure, relative volume, and liquid yields) are strongly influenced by the presence of water.
Over the past decades, though different thermodynamic models have been
TE D
evaluated by traditional equations of state such as PR, PR78, SRK, SRK-HV, UNIQUAC [12], and UNIFAC [13], none of the above conventional equations explicitly takes into account the interactions between molecules, which involve
EP
associating compounds. Nowadays, many attempts have been made in the development of an EOS that is considered a system containing associating compounds
AC C
[14-19]. The cubic-plus-association (CPA) equation of state [20-21] is the most recent EOS that combines the physical part of the SRK EOS [22] with the association term based on the Statistical Association Fluid Theory (SAFT) [16, 23]. The CPA EOS has been widely used to pure components and Vapor-Liquid equilibrium, Liquid-Liquid equilibrium
and
Solid-Liquid
equilibrium
for
associating-associating
and
associating-inert systems [20-21, 24-28]. For many petrochemical processes, the
3
ACCEPTED MANUSCRIPT
description of the water/hydrocarbon system is a challenging aspect of development. Over a wide range of temperatures and pressures, systems of water exhibit the limited
RI PT
miscibility of hydrocarbons [29-31]. The prediction of the CPA EOS shows a good correlation with the experimental data on water/hydrocarbon systems [29-30, 33-35].
In this work, we performed CCE and CVD tests on a gas condensate system with
SC
water vapor to investigate the influence of water vapor on the phase behavior of
condensate fluid and the gas phase. Similar experiments for a water free gas
M AN U
condensate sample were performed for comparison. In addition, several equations of state (PR, PR78, SRK, SRK-HV, and CPA-SRK) were employed to demonstrate the solubility data and the prediction of gas-related properties. 2. Experimental Apparatus and Procedures
TE D
2.1 Experimental apparatus
To perform the pressure/volume/temperature (PVT) experiments, we set up a
EP
high-pressure and high-temperature laboratory. A schematic of the experimental setup is presented in Fig. 1. A mercury-free DBR (Donald B. Robinson Company) PVT cell
AC C
was used to study the phase behavior properties of the fluid samples. A transparent glass cylinder cell with a volume of approximately 400 mL and a maximum working pressure of 70 MPa at 473K was one of the most important parts of the experimental system. The test fluid sample was placed in the cell by pushing a Ruska pump connected to the top of the cell. The volume of the injected sample was monitored by a cathetometer. A magnetic mixer arranged on the end cap of the cell was utilized to reduce the time required to reach equilibrium during operation. To ensure the 4
ACCEPTED MANUSCRIPT
accuracy of the measurement, the volume of the PVT cell, the temperature readers, and the pressure transducers were calibrated frequently before the start of the
RI PT
experiment (measured quantities temperature±0.1℃, pressure±0.05MPa, volume±
Intermediate Container
Chromatograph
Hydrometer
Separator
Gasometer
Separator of Ground
M AN U
Viscometer
SC
0.1cm3).
PVT cell
Automatic Pump
Fig. 1. Schematic diagram of the experimental apparatus [36].
TE D
2.2 Phase equilibrium measurement.
2.2.1 Water free gas condensate measurements Phase equilibrium measurements usually include CCE and CVD experiments. In
EP
this study, the CCE test consisted of varying the pressure and measuring the resulting volume of the single phase fluid above saturation pressure. Measuring the volumes of
AC C
the vapor and liquid phases below the saturation pressure was done first while trying to determine the dew point pressure. The dew point pressure was determined by reducing the system pressure in small
increments until tiny liquid droplets emerge. To confirm the accuracy of the dew point pressure, great attention and an increased amount of concentration were required to perform three repetitive tests by increasing and decreasing the pressure around the
5
ACCEPTED MANUSCRIPT
dew point. When the pressure of PVT cell was lowered to the dew point pressure, both the amount and the size of droplets increased with the decrease of pressure. This
RI PT
phenomenon continued until a new gas–liquid equilibrium was reached at the current pressure, and the above process would have been repeated until the pressure was reduced to approximately 5 MPa.
SC
After the CCE test, a CVD test was performed continuously to assess the
recovery of the gas and liquid phase at different depletion pressures. This experiment
M AN U
consists of starting with a volume of fluid at its saturation pressure, which again defines the PVT cell or control volume for the experiment. Then the pressure is dropped by 3 to 4 MPa or so, whereupon the fluid becomes two phases and expands in volume. Any excess volume over and above the cell is removed by taking off the
TE D
gas, which is analyzed compositionally and volumetrically, as well as noting the number of moles through a valve on the top of the PVT cell. Furthermore, the percentage of liquid in the remaining fluid, the cell volume, defines the liquid
EP
saturation.
After the above two tests, the gas condensate sample was flashed into a container
AC C
at standard conditions (0.1 MPa and 289.15 K). The separated gas was collected in a gasometer and its composition was analyzed by a chromatograph. The properties of the condensate liquid were also measured. The gas condensate ratio was then calculated based on the amounts of gas and condensate collected.
6
ACCEPTED MANUSCRIPT
2.2.2 Gas condensate with water vapor system The pressure/volume/temperature experiments for a gas condensate sample with
RI PT
gaseous water were initiated by adding a certain amount of water free gas condensate sample prepared beforehand and an excess amount of aqueous phase to the sample
container. In order to mix well, the container was heated to reservoir temperature and
SC
rocked constantly. After about 48 hours, the gas-water equilibrium was regarded as achieved. The gas phase was saturated entirely with water vapor and the aqueous
M AN U
phase was completely dissolved with gases. Then the superfluous water was discharged through a valve at the bottom of the sample container to ensure that only a gas phase existed in the container. The prepared gas sample was then transported into the PVT cell. CCE and CVD tests were performed via similar procedures described
TE D
earlier for the water free gas condensate sample.
In this work, the content of water vapor in the gas phase was determined based on the method described in our previous work (Che et al., 2008). An increased amount of
EP
concentration was required to ensure the accuracy of the test. Thereafter two sets of
AC C
flashes were conducted. The first flash was with the prepared gas condensate sample containing water vapor. In flashing, the outlet fluid was frozen by liquid nitrogen in a separation vessel and three phases were observed gradually: (a) a gas phase, (b) a hydrocarbon liquid phase, and (c) an aqueous phase. The gas was collected and analyzed, the properties of the hydrocarbon liquid were measured, and the amount of water was recorded. The GCR was then calculated.
7
ACCEPTED MANUSCRIPT
The second flash was performed on the aqueous phase discharged from the container earlier. This step was required to obtain the composition of hydrocarbons
RI PT
dissolved into the aqueous phase. 3. Results and discussion 3.1 The properties of samples
SC
The gas condensate samples used in this work were collected from a gas
M AN U
condensate reservoir in southwest China. The reservoir pressure and temperature for this reservoir are 34 MPa and 351.15K, respectively. The experimental composition analysis results are provided in Table 1. The first and second columns show the separator gas and oil compositions analyzed by a gas chromatograph. The third column shows the water free gas condensate compositions obtained by recombining
TE D
the separator gas and oil phase (Sample 1) according to the GCR. The fourth column shows the compositions of the recombined gas condensate sample with the water
EP
vapor (Sample 2) obtained by recombining of a certain amount of water free gas condensate sample and an excess mount of water. The last column shows the
AC C
compositions of the aqueous phase that was discharged from the sample container, and this aqueous phase was analyzed by a gas chromatograph. The separated GCR is 2879 m3/m3 under the conditions of 4.8 MPa and 289.15K, and the total GCR of the reservoir fluid is 3001 m3/m3 (calculated at standard conditions). A reduction in GCR
from 3001 m3/m3 for Sample 1 to 2879 m3/ m3 for Sample 2 was noted. This reduction is attributed to the dissolution of light components (mainly CH4, C2H6, and CO2) in the aqueous phase and the volatilization of water in the gas phase. 8
ACCEPTED MANUSCRIPT
Table 1. The compositions of samples. Sample 2 Gas Condensate with Water Vapor (mol %)
Component
abbreviations
Separator Gas (mol %)
Nitrogen
N2
0.20
0.00
1.47
CO2
1.42
0.00
1.56
Methane
C1
88.17
0.05
80.93
Ethane
C2
6.70
0.02
5.62
Propane
C3
1.98
0.07
Isobutene
iC4
0.37
Butane
nC4
0.41
2-Methlbutane
iC5
0.14
Pentane
nC5
0.12
Hexane
C6
0.49
Heptane
C7
0.00
Octane
C8
0.00
Nonane
C9
0.00
Deane
C10
Undecane Water GCR
Aqueous Phase (mol %)
0.0009
1.51
0.0082
80.11
0.2130
5.48
0.0096
3.88
3.87
0.0016
0.18
1.10
1.08
0.0000
0.14
1.28
1.28
0.0000
0.50
0.32
0.32
0.0000
0.17
0.20
0.20
0.0000
5.59
0.43
0.43
0.0000
4.57
0.17
0.18
0.0000
7.11
0.36
0.37
0.0000
5.72
0.35
0.39
0.0000
0.00
9.26
0.44
0.49
0.0000
C11
0.00
67.52
1.92
2.18
0.0000
H2O
0.00
0.00
0.00
SC
1.42
TE D
dioxide
Water Free Gas Condensate (mol %)
M AN U
Carbon
Separator Oil (mol %)
RI PT
Sample 1
3
0.67 3
3001m /m
3
99.7667 3
2879 m /m
EP
Table 2 shows the percentage of average absolution deviation (AAD calculated
AC C
by the Eq.1) between the experimental and calculated values in the solubility of water in the vapor phases (Ywater) and in the solubility of hydrocarbons in the aqueous phase
(XHC). The table also shows the amount of water in the aqueous (Xwater) phase by using different equations of state where the AADs for solubility are estimated and summarized. AAD(%) =
xexp,i − xcal ,i 1 NP abs( ) × 100 ∑ NP i =1 xexp,i
9
(1)
ACCEPTED MANUSCRIPT
To improve the prediction result, the interaction parameters were adjusted by minimizing the function (Smith and Srivastava, 1986) defined by Eq.2, and this
sat Pcalsat − Pexp Q =∑ P sat i =1 exp NP
2
NP V liq − V liq exp cal + ∑ liq i i =1 Vexp
2
i
RI PT
equation is solved using the least square method: (2)
Where NP is the number of experimental data points, Psat is the vapor pressure, and
SC
V liq is the saturated liquid volume. For the vapor-liquid equilibrium (VLE) calculation,
CPA pure components parameters for associating the compounds and hydrocarbons
M AN U
used in this work were obtained from the literature [29, 39], and the water was modeled as a 4C scheme [39]. Table 3 only presents the interaction parameters of water-hydrocarbon for the SRK-HV and SRK-CPA EOSs. The calculation procedure of other equations of state is similar to the above two equations of state.
TE D
A summary of the VLE results shown in Table 2 demonstrate that, in most of the cases, the CPA EOS gives a relatively accurate prediction of the water content in the
EP
vapor phase with only 1.88% AAD at the temperature of 351.15K followed by the SRK-HV equation with 5.03 AAD%. Other conventional equations of state have a
AC C
significant deviation in prediction solubilities. In the following calculation process, only the above two correction equations are applied. For the non-polar substance system, the CPA-SRK EOS can be simplified as the SRK EOS. Table 2. Percentage average absolute deviation (% AAD) between experimental water solubilities and calculated values from different equation of states. EOS
AAD in Xwater (%)
AAD in XHC (%)
AAD in Ywater(%)
PR
0.18
42.92
133.04
PR78
0.18
41.49
132.78
10
ACCEPTED MANUSCRIPT
SRK
0.19
45.59
136.98
SRK-HV
0.18
22.06
5.03
CPA-SRK
0.03
9.01
1.88
Table 3. The binary interaction parameters of SRK-HV and SRK-CPA equations of state. Component
Binary Interaction Parameters SRK-HV SRK-CPA α H 2O − j k H 2O − j
RI PT
Binary Interaction Parameters SRK-HV SRK-CPA α H 2O − j k H 2O − j 0.0573
-0.0481
nC5
-0.0033
-0.0249
CO2
0.0020
0.0265
C6
-0.0060
0.0080
C1
-1.026
0.0073
C7
-0.0007
0.0094
C2
-0.0214
0.0043
C8
0.0014
0.0126
C3
-0.0363
0.0079
C9
0.0048
0.0301
iC4
-0.0163
0.0043
C10
0.0103
0.0319
nC4
0.0057
0.0321
iC5
-0.0054
0.0207
M AN U
N2
SC
Component
C11
-2.9959
0.0084
3.2 The influence of water vapor on phase behavior
Two gas mixtures are shown in Table 1 with and without water vapor. The
TE D
mixtures were used to study the effect of water vapor on the phase behavior properties of selected gas condensate reservoirs. The procedure of Pedersen and Milter [7] is utilized to characterize the above two samples and the characterized results are
EP
presented in Table 4. By the calculation method proposed by Lindeloff and Michelsen
AC C
[9], the SRK-HV was applied to estimate the phase envelope in this work. As shown in Fig. 2, the phase envelope of the water free gas condensate sample is surrounded by the phase envelope of the water vapor sample. Moreover, the phase envelope gives the critical temperature and pressure of 178.16 K and 5.91 MPa for the water free gas condensate sample and 180 K and 6.83 MPa for the water vapor sample. In contrast to the phase diagram of water free gas condensate sample, the phase envelope of the water vapor sample calculated by the method provided by Lindeloff and Michelsen [9] 11
ACCEPTED MANUSCRIPT
divided the phase diagram into four regions, as shown in Fig. 2. Region A represents the single gas phase region; Region B represents the gas-oil two-phase region; Region
RI PT
C represents the gas-water two-phase region; and Region D represents the gas-water-oil three-phase region. The symbol “2-Aq” means the dew point line that separates the single and two-phase regions and sets the aqueous phase as the initial
SC
phase. The symbol “3-Aq” means the phase envelope line that separates the two and three phase regions and sets the aqueous phase as the initial phase. In the same way,
M AN U
for the calculation of the initial hydrocarbon phase, 2-HC and 3-HC have the same meaning.
Under the temperature and pressure of a gas reservoir, the initial state of the sample with water vapor is a single gas phase. After the pressure was lowered to
TE D
below the dew point pressure, two phases emerged gradually: (a) a hydrocarbon gas phase and (b) a hydrocarbon liquid phase. This indicates that the liquid dropout is solely composed of condensate oil.
Table 4. Characterized gas condensate mixtures.
EP
Sample 1
AC C
Component N2 CO2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9
Mol (%) 1.470 1.560 80.93 5.620 3.880 1.100 1.280 0.320 0.20 0.430 0.170 0.360 0.350 12
Sample 2 Component N2 CO2 C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9
Mol (%) 1.420 1.510 80.110 5.480 3.870 1.080 1.280 0.320 0.200 0.430 0.180 0.370 0.389
ACCEPTED MANUSCRIPT
ρC19-C49 MC19-C49
0.8013 298
C10 C11 C12 C13 C14 C15 C16 C17-C19 C20-C51 H2O ρC20-C51 MC20-C51
35
A
Pressure(MPa)
25 20 15
M AN U
C
30
0.490 0.556 0.389 0.297 0.258 0.157 0.146 0.198 0.183 0.669 0.8015 315
RI PT
0.440 0.529 0.383 0.278 0.201 0.146 0.105 0.132 0.145
SC
C10 C11 C12 C13 C14 C15 C16 C17-C18 C19-C49
B
10
D
0 150
TE D
5
200
250
300
350
400
450
500
550
Temperature(K)
EP
water free sample 3-Aq 3-HC Cp of water free sample
B—gas-oil two phase region D—gas-water-oil three phase region
AC C
A—single gas phase region C—gas-water three phase greion
2-Aq 2-HC The condition of reservoir Cp of water vapor sample
Fig. 2. The phase envelope for both gas condensate samples
The CCE test results suggest that the presence of water vapor not only
significantly increases the dew point pressure, but it also raises the amount of liquid dropout, nevertheless there seems to be no obvious difference in the relative volumes obtained for both samples (all relative volumes are the ratio of gas volumes at different pressures and the gas volume under dew point pressure, see Figs. 3–5 and
13
ACCEPTED MANUSCRIPT
Table 5). The measured results demonstrated that the presence of water vapor increases the dew point pressure by almost 1 MPa, and this can be also seen in the
RI PT
calculated results shown in Fig. 2, where the values of Sample 1 and Sample 2 are 30.34 MPa and 31.12 MPa, respectively. Due to the large critical temperature and the
critical pressure of water, here, water can be considered as a heavy component. This
SC
designation makes the content of light components in the mixture decrease and the
proportion of the heavy components increase, and thus it increases the dew point
M AN U
pressure of the system. 10
SRK SRK-HV
8
6
4
2
0 0
TE D
Reletivw volume
Experiment
7
14
21
28
EP
Pressure(MPa)
AC C
Fig. 3. The relative volume of the water free gas condensate sample
14
35
ACCEPTED MANUSCRIPT
10
CPA-SRK SRK-HV
8
Reletive volume
Experiment
4
2
0 7
14
21
28
35
SC
0
RI PT
6
Pressure(MPa)
M AN U
Fig. 4. The relative volume of the water vapor gas condensate sample 10
Experiment with water vapor sample Experiment with free water vapor sample
6
4
2
0 0
TE D
Reletive volume
8
7
14
21
28
35
EP
Pressure(MPa)
AC C
Fig. 5. The comparison of the experimental relative volume between the two gas condensate samples Table 5. The deviation between the calculated results and the experimental data Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
3.90
SRK-CPA
0.69
SRK-HV
1.48
SRK-HV
2.51
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 4.2% calculated by SRK, and 1.7% by SRK-HV while that of water vapor sample is 0.73 % and 2.68% by the SRK-CPA and SRK-HV, respectively.
15
ACCEPTED MANUSCRIPT
For both samples, the curves between the retrograde condensate saturation and the pressure appear smooth, and these data show a trend of a quick increase that
RI PT
reached a maximum and subsequently reduce with a further decrease in pressure (see Figs. 6–8). Also, it can be seen in Fig. 8 that, owing to the presence of water vapor,
the curve of the gas condensate with the water vapor sample moves entirely toward
SC
the pressure expansion side of the X-axis in comparison with the curve of the water free gas condensate sample. This phenomenon caused an approximately 7.12–8.51%
M AN U
increase in the maximum liquid dropout and 18–20MPa growth in the maximum retrograde condensate pressure. This increasing trend is mainly caused by the interphase mass transfer between the gas and aqueous phase, leading to an increase in the mole fraction of the water vapor and a decrease in the mole fraction of light
TE D
hydrocarbons in the gas phase. Thus, the presence of water will accelerate the precipitation of the heavy components, and more liquid will be released. Because of this, the retrograde condensate saturation curve of the water vapor sample is above the
8
AC C
Retrograde condensate saturation（%）
EP
curve of the water free sample.
6
4
SRK
2
SRK-HV Experiment 0 0
7
14
21
Pressure(MPa)
16
28
35
ACCEPTED MANUSCRIPT
Fig. 6. The retrograde condensate saturation of water free gas condensate sample for CCE test
RI PT
8
6
4 CPA-SRK SRK-HV
2
Experiment
SC
Retrograde condensate saturation(%)
10
0 0
7
14
21
28
M AN U
Pressure(MPa)
35
Fig. 7. The retrograde condensate saturation of the water vapor gas condensate sample for CCE test
8
TE D
6
4
Experiment with water vapor sample
2
Experiment with free water vapor sample
0
EP
Retrograde condensate saturation (%)
10
0
7
14
21
28
35
Pressure(MPa)
AC C
Fig. 8. The comparison of the retrograde condensate saturation between the two gas condensate samples for CCE test Table 6. The deviation between the calculated results and the experimental data on the retrograde condensate saturation of the CCE test Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
7.50
SRK-CPA
2.46
SRK-HV
4.59
SRK-HV
9.86
17
ACCEPTED MANUSCRIPT
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 7.79% calculated by SRK, and 5.06% by SRK-HV while that of water vapor sample is 2.66 % and 10.08% by the SRK-CPA and SRK-HV, respectively.
Figs. 9–11 provide the retrograde condensate saturation results for the CVD test
RI PT
where the variation of the curves is similar to that observed in the CCE test and the
maximum retrograde condensate saturation increases from 8.52% for the water free sample to 9.6% for the water vapor sample. Although the curves show the same
SC
regularity, in general, the values of CCE test results are slightly smaller than the
8
6
4 SRK
2
TE D
Retrograde condensate saturation (%)
10
M AN U
values of the CVD test.
SRK-HV
Experiment
0 0
7
14
21
28
35
Pressure(MPa)
10
AC C
Retrograde condensate saturation(%)
EP
Fig. 9. The retrograde condensate saturation of the water free gas condensate sample for CVD test
8
6
4
2
CPA-SRK SRK-HV Experiment
0 0
7
14
21
Pressure(MPa)
18
28
35
ACCEPTED MANUSCRIPT
Fig. 10. The retrograde condensate saturation of the water vapor gas condensate sample for CVD test
RI PT
8
6
4
2
Experiment with free water vapor sample Experiment with water vapor sample
0 0
7
14
21
SC
Retrograde condensate saturation (%)
10
28
M AN U
Pressure(MPa)
35
Fig. 11. The comparison of the retrograde condensate saturation between the two gas condensate samples for CVD test Table 7. The deviation between the calculated results and the experimental data on the retrograde condensate saturation of the CVD test Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
AAD (%)
EOS
AAD (%)
SRK
16.49
SRK-CPA
1.44
SRK-HV
4.59
SRK-HV
TE D
EOS
4.56
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 16.52% calculated by SRK, and 4.66% by SRK-HV while that of water vapor sample is
EP
1.45 % and 4.28% by the SRK-CPA and SRK-HV, respectively.
For engineers who are most concerned about the cumulative recovery, all
AC C
cumulative recoveries shown in Figs. 12–17 are defined as cumulative amounts of the gas or liquid phases at different pressures relative to the total amounts of the gas or liquid phases. The ultimate recoveries of the gas phase (see Figs. 12–14) are 82.34% and 92.51%, and the values of the liquid phase (see Figs. 15–17) are 17.59 % and 16.45% for the water free sample and water vapor sample, respectively. Studies have led to the conclusion that there is relatively smaller difference in the gas cumulative recoveries while there is an intersection point of the liquid recovery curve. The values 19
ACCEPTED MANUSCRIPT
of the water vapor sample are slightly larger on the right side of the intersection point, and an opposing case is observed on the left side of the intersection point. This can be
RI PT
explained by the fact that the rise of the dew point pressure leads to the condensation of the heavy component in advance; thus causing a significant loss in the condensate liquid. 90 75
SC
SRK-HV
Experiment
60 45 30 15 0 0
7
M AN U
Cumulative recovery (%)
SRK
14
21
28
35
Pressure(MPa)
80 60
CPA-SRK SRK-HV Experiment
EP
Cumulative recovery(%)
100
TE D
Fig. 12. The cumulative recovery of the gas phase of the water free gas condensate sample
40
AC C
20 0
0
7
14
21
28
35
Pressure(MPa)
Fig. 13. The cumulative recovery of the gas phase of the water vapor gas condensate sample
20
ACCEPTED MANUSCRIPT
90
Experiment with free water vapor sample Experiment with water vapor sample
60 45
RI PT
Cumulative recovery (%)
75
30 15 0 0
7
14
21
28
35
Pressure(MPa)
condensate samples
SC
Fig. 14. The comparison of the cumulative recovery of the gas phase between the two gas
M AN U
Table 8. The deviation between the calculated results and the experimental data on the cumulative recovery curves of gas phase Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
19.41
SRK-CPA
4.67
SRK-HV
7.03
SRK-HV
5.39
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of
TE D
water free sample is 17.78% calculated by SRK, and 7.11% by SRK-HV while that of water vapor sample is 4.72% and 5.51% by the SRK-CPA and SRK-HV, respectively.
16
EP
Cumulative recovery (%)
20
AC C
12
8
4
SRK SRK-HV Experiment
0
0
7
14
21
Pressure (MPa)
21
28
35
ACCEPTED MANUSCRIPT
Fig. 15. The cumulative recovery of the liquid phase of the water free gas condensate sample 20
Cumulative recovery(%)
16
RI PT
12
8 CPA-SRK
4
SRK-HV
0
7
14
21
Pressure(MPa)
SC
Experiment
0
28
35
M AN U
Fig. 16. The cumulative recovery of the liquid phase of the water vapor gas condensate sample
16
12
8
TE D
Cumulative recovery (%)
20
Experiment with free water sample
4
Experiment with water vapor sample
0
7
14
EP
0
21
28
35
Pressure(MPa)
AC C
Fig. 17. The comparison of the cumulative recovery of the liquid phase between the two gas condensate samples Table 9. The deviation between the calculated results and the experimental data on the cumulative recovery curves of liquid phase Water Free Gas Condensate Sample
Condensate Gas with Water Vapor Sample
EOS
AAD (%)
EOS
AAD (%)
SRK
12.22
SRK-CPA
3.27
SRK-HV
8.11
SRK-HV
6.16
Note: the average AAD of the prediction with respect to the experimental accuracy for the measured quantity of water free sample is 12.21% calculated by SRK, and 8.12% by SRK-HV while that of water vapor sample is 3.15% and 5.76% by the SRK-CPA and SRK-HV, respectively.
22
ACCEPTED MANUSCRIPT
It was mentioned that the SRK-CPA and SRK-HV equation of states are typically applied, which yield acceptable errors in the estimation of gas and liquid related
RI PT
properties seen in Tables 5–9. It is not hard to see that the CPA-SRK corrects the experimental results with a smaller error. 4. Conclusions
SC
In this work, equilibrium CCE and CVD tests were performed on gas condensate samples with and without water vapor. Although the solubility of water in the gas
M AN U
phase at reservoir conditions is limited, the influence of the water on the gas related properties of the reservoir fluid is quite considerable. This study shows that very good results can be predicted by the CPA-SRK EOS. The following conclusions can be drawn based on the tests conducted:
TE D
The presence of water vapor not only increases the dew point pressure, but it also leads to a change in other gas-related properties of gas condensate reservoirs (e.g. the
EP
P/V relationship, the amount of liquid dropout, and the recoveries). Some properties, especially the liquid dropout of the curves, move wholly toward the pressure
AC C
expansion side. This indicates that there is a significant deviation when the presence of water is ignored.
As known from the simulation results of the water vapor sample, there are two
cases: (a) initially saturated water and (b) oversaturated water. When the pressure decreases below the dew point pressure, the condensate liquid of the initially saturated water consists solely of hydrocarbons in liquid phase while the condensate of
23
ACCEPTED MANUSCRIPT
oversaturated water includes not only the hydrocarbons liquid, but also the aqueous phase.
RI PT
The CPA EOS has been applied to predict the solubility and gas-related properties of gas condensate reservoirs. A good agreement between experimental data and
predictions was obtained, demonstrating that this equation of state is suitable for
AC C
EP
TE D
M AN U
SC
multicomponent mixtures containing water and hydrocarbons.
24
ACCEPTED MANUSCRIPT
Acknowledgment
RI PT
This work was supported by the National Natural Science Foundation of China (No. 51374179, “Theory and molecular dynamics study on CO2-crude oil non-equilibrium
diffusion considering capillary pressure and adsorption”) and the “National
SC
Scholarship in the Western Region Talent Training Special Project Funding (No. 201508515157).”
M AN U
References
[1] M.E. Aily, M.H.M. Khalil, S.M. Desouky, M. H. Batanoni, M.R.M. Mahmoud. Egypt. J. Pet.22 (2013)129-136.
[2] J.K. Drohm, R.D. Trengrove, W.H. Goldthorpe. Society of Petroleum Engineers, 1988. [3] T.O. Amao, A.M. Amao. Society of Petroleum Engineers, 2014.
[4] T. Ahmed. Third ed., Gulf publishing company, Houston, Texas, 2007. [5] T.H. Ahmed. SPE Reservoir Eng. 3(1986)337-348.
TE D
[6] H.C. Song, Y. Jin. Journal of Qiqihar University, 3(2012)79-82.
[7] K.S. Pedersen, J. Milter. SPE Annual Technical Conference and Exhibition, 2004 [8] K. Sunil, A.D. Mohammad, S. Selim. SPE Reservoir Eval. Eng. 6(2000)294-300. [9] L. Niels, M. L. Michelsen. SPE J.8 (2013)298-303. [10] V.S.S. Bang, G.A. Pope, M.M. Sharma. SPE J.15 (2010)952-962.
EP
[11] S. Kokal. SPE Reservoir Eval. Eng. 6(2003):412-420. [12] T.F. Anderson, J.M. Prausnitz. Ind. Eng. Chem. Process Des. Dev.17 (1978)561-567. [13] P.A. Gupte, R.P. Danner. Ind. Eng. Chem. Res. 26(2002):2036-2042.
AC C
[14] S.H. Huang. M. Radosz. Fluid Phase Equilib.70 (1991)33-54.
[15] I.G.Economou, G.D.Ikonomou, P.Vimalchand, M.D.Donohue.AlChE J.36 (1990) 1851-1864. [16] W.G.Chapman, K.E.Gubbins, G.Jackson, M.Radosz. Ind.Eng.Chem.Res.29 (1990)1709-1721. [17] A. Anderko. Fluid Phase Equilib.65 (1991)89-110. [18] S.J. Suresh, J.R. Elliott. Ind. Eng. Chem. Res.30 (1991)524-532. [19] G.D. Ikonomou, M.D. Donohue. Fluid Phase Equilib.39 (1998)129-159. [20]G.M. Kontogeorgis, E.C.Voutsas, V.Y.Iakovos, D.P.Tassios. Ind.Eng.Chem.Res. 35(1996) 4310-4318.
[21] I.V. Yakoumis, G.M. Kontogeorgis, E.C. Voutsas, D.P.Tassios. Fluid Phase Equilib.130 (1997) 31-47.
25
ACCEPTED MANUSCRIPT
[22] G. Soave. Chem. Eng. Sci. (1972)1197-1203. [23] S.H. Huang. M. Radosz. Fluid Phase Equilib.60 (1990) 81-98. [24] G.M. Kontogeorgis, M.L. Michelsen, G.K. Folas, S.Derawi, N.V.S, E.H.Stenby. Ind. Eng. Chem. Res. (2006)2645-56.
other compounds. CRC Press, 1980. 1527-1538.
RI PT
[25] G.K. Folas, G.M. Kontogeorgis, M.L. Michelsen, E.Stenby. Glucuronidation of drugs and
[26] G.K. Folas, S.O. Derawi, M.L. Michelsen, E.H.Stenby, G.M. Kontogeorgis. Fluid Phase Equilib.228 (2005)121-126.
[27] R.A. Wilsak, S.W. Campbell, G. Thodos. Fluid Phase Equilib.33 (1987)157-171. [28] C. T. Liu, W. T. Lindsay, J. Solution Chem.1 (1972) 45-69.
[30] M. Medeiros. Fluid Phase Equilib. 368(2014)5-13.
SC
[29] M.B.Oliveira, J.A.P. Coutinho, A.J. Queimada. Fluid Phase Equilib.258 (2007)58-66.
[31] M. Zirrahi, H. Hassanzadeh, J. Abedi. Fuel.159 (2015)894-899.
M AN U
[32] M. Medeiros. Fluid Phase Equilib. 392(2015)65-73.
[33] A.J. Queimada, I M. Marrucho, E.H. Stenby, G. Kontogeorgis, C. Miqueu, J.A.P. Coutinho. Ann Oncol.26 (2016)132-135.
[34] F. Masoodiyeh, M.R. Mozdianfard,J. Karimi-Sabet. Korean J. Chem. Eng.30 (2013)201-212. [35] M. Hajiw, A. Chapoy, C. Coquelet. Can. J. Chem. Eng.93 (2015):432–442. [36] X. Bian, Z. Du, Y. Tang, J.Du.J.Petrol.Sci.Eng.82 (2012)38-43.
[37] J. Che, P. Guo, J. Fan, J. Du. Natural Gas Exploration & Development. 31(2008)44-48.
TE D
[38] D.S. Buford, S. Rakesh. Elsevier, 1986.
[39] L.C.D. Santos, S.S. Abunahman, F.W. Tavares, V. R. R. Ahón, G. Kontogeorgis. Ind. Eng. Chem. Res.54 (2015)6812-6824.
[40] M.J. Huron, J. Vidal, Fluid Phase Equilib.3 (1979)255–271.
AC C
EP
[41] R.L. Scott. J. Chem. Phys. 25(1956)193-205.
26
ACCEPTED MANUSCRIPT
1) Investigate the effect of water vapor on condensate gas fluid 2) Test the solubility of water in gas condensate fluid under reservoir condition.
RI PT
3) Analyze the effect of water on hydrocarbons phase behavior experimentally. 4) Suggest CPA EOS as the best choice for calculating the properties of aqueous
AC C
EP
TE D
M AN U
SC
fluids.