SPE 161478
Experimental Investigation of Wet Gas Dew Point Pressure Change with
Carbon Dioxide Concentration
Odi, U. Texas A&M University, El Hajj, H. Texas A&M University at Qatar, Gupta, A. Texas A&M University at
Qatar
Copyright 2012, Society of Petroleum Engineers
This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11–14 November 2012.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been
reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
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Abstract
Dew point pressure is a critical measurement for any wet gas reservoir. Condensate blockage is likely when the
reservoir pressure decreases below the dew point pressure and this can result in a reduction of gas productivity. Errors in
measuring dew point pressure can lead to errors in the estimation of the onset of condensate blockage and thus be detrimental
to the management of wet gas fields. This work presents experimental verification of a new method of determining dew
point pressures for wet gas fluids. Results obtained from this method are compared to calculated values based on Peng
Robinson equation of state.
Dew point pressure determination is important when devising solutions on how to prevent condensate blockage.
One possible treatment fluid, carbon dioxide, has the ability to lower dew point pressures and thus delay the onset of
condensate blockage. The novel method presented in this work was applied to determine the experimental dew point
pressure of several wet gas mixtures as a function of carbon dioxide concentration. These experiments also show the
potential of using carbon dioxide to lower dew point pressures in wet gas fields.
Experimental results show close match between the experimental estimates of dew point pressure and the Peng
Robinson calculations. Experimental results also support the general observation that carbon dioxide has the ability to lower
the dew point pressure of wet gas fields.
The results of this work are useful in Enhanced Oil/Gas Recovery processes that utilize carbon dioxide and for Huff
and Puff which uses carbon dioxide to remove and prevent further build-up of condensate banks in wet gas reservoirs. This
work investigates experimental conditions showing the change in dew point pressure as a function of carbon dioxide
concentration. This dynamic relationship can be used to tune equation of state models which, in turn, allows more accurate
reservoir modeling of hydrocarbon recovery process.
Introduction
Condensation is a critical factor in determining the performance of wet gas fields. Condensation in the near
wellbore region can lead to a dramatic reduction in gas flow due to the reduction of effective permeability to gas. Gas
relative permeability reduction in the near wellbore region is primarily caused by an increase in liquid saturation due to
condensation. This can be observed by studying a typical gas relative permeability relationship as illustrated in Figure 1. In
a gas condensate system, a small reduction of gas phase saturation can correspond to an exponential decrease in gas relative
permeability. Figure 1 illustrates that as the liquid saturation increases, and the gas phase decreases from the maximum
saturation value, there is a dramatic decrease in a relative permeability.
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SPE 161478
Figure 1: Relative Permeability Relationship between Gas and Condensate Phase
In wet gas reservoirs, increase in liquid saturation, which is the primary reason for reduction of gas relative
permeability, is caused when the bottom hole pressure drops below the dew point pressure. Gas reservoir operators often
allow this in absence of accurate values for dew point pressure or in order to maintain economic gas production rates from the
wells. In order to accurately identify minimum pressure level that must be maintained in a gas reservoir, dew point pressure
measurements can be conducted using a representative sample of the reservoir fluid in a PVT apparatus. For a wet gas
reservoir, PVT experiments and analysis are needed to measure the dew point pressure at the known reservoir temperature.
The simplest conventional method of determining the dew point pressure of a hydrocarbon gas mixture is a visual test that
requires collection of a representative wet gas sample at reservoir conditions and testing it in a PVT cell chamber with a glass
window. During the dew-point experiment, the sample is first equilibrated at the initial reservoir conditions of pressure and
temperature and then, starting from a high pressure gas phase, it is gradually depressurized in the PVT cell to observe
physical changes through the glass window into the cell. The first instant of condensation, seen as slight clouding of the
window, is referred to as the dew point pressure for the sample. The limitation of this method is that the observation of
condensation can be subjective and contribute to erroneous estimation of dew point pressure leading to inaccurate wet gas
characterization.
Another method of dew point measurement involves using the acoustic signature of the sample fluid. The acoustic
method relies on acoustic theory which states that the acoustic response is proportional to the velocity of signal through the
fluid (Sivaraman et al, 1997). To determine the dew point using the acoustic method requires using an apparatus that is
capable of transmitting an acoustic signal through a reservoir fluid and receiving and analyzing the signal that transmits
through the reservoir fluid. The travel time and alteration in signal during transit through the reservoir fluid is used to
characterize the physical phase of the reservoir fluid. Determination of the dew point pressure using this method requires
performing a constant composition expansion test similar to the visual method. The first instance of a liquid signature in the
vibrational response during this test is defined as the dew point pressure. The limitation of this method is that it still requires
the visual method to validate the estimated dew point. Thus, any PVT apparatus that is designed to implement the acoustic
method must have a window cell to ensure accuracy, in addition to the equipment that can transmit and receive the acoustic
signal. The capital investment needed for the acoustic method can be significantly higher than for the standard PVT cell used
for the visual method.
Potsch et al. (1996) presented a method to determine the dew point pressure graphically. Their method involved
using the real gas equation of state to calculate the total moles in the reservoir fluid sample for several measurements of
pressure above the dew point pressure. They proposed that below the dew point pressure, condensation will cause calculated
moles in the gas phase to be different from the actual number of moles. They proposed that the first instance from the
deviation from the true amount of moles indicates dew point pressure. Their work may be in error because the real gas
equation of state is not valid for fluids near the saturation pressure as indicated by their plots of the calculated molar quantity
changing with pressure above dew point pressure. For a valid method, the calculated amount of moles would have remained
constant because of the conservation of mass in the PVT cell (no mass exits or leaves the PVT cell). Potsch et al.’s attempt to
characterize the dew point pressure appears to be theoretically inaccurate.
The method proposed in this paper is based on tracking changes in compressibility to pinpoint dew point pressure
measurements in wet gas fluid samples. Using this method, this work demonstrates the potential of using CO2 to lower the
dew point pressure as a solution to condensate blockage. Comparisons with Peng Robinson equation of state are used to
validate the approach illustrated in this work.
SPE 161478
3
Saturation Pressure Theory
Dew point pressure can be described as the pressure at which a gas starts condensing into a liquid phase. Pressure
and temperature phase diagrams are generally used to describe bubble points and dew points as functions of pressure and
temperature. For example, Figure 2 illustrates a pressure and temperature phase diagram for a wet gas that exhibits retrograde
condensation. The dew-point line, the line that is to the right of the critical point can be used to describe variation of dew
point pressure with temperatures.
Figure 2: Pressure and Temperature Diagram for Wet Gas/Condensate with CCE Isotherm
When analyzing the results of constant composition expansion (CCE) experiment, a general test used to estimate
bubble and dew points using the visual method, it is important to understand the thermodynamic changes that occur to the
reservoir fluid during phase change. Determination of bubble points using the graphical method based on CCE tests is made
possible by the large differences between the compressibility of liquid phase less dense gas phase.
Determination of phase changes involved in the transition from the gas phase to the liquid phase is much more
difficult due to indistinguishable slope changes. Such is the case when looking at dew points of gas condensates. This can be
illustrated by considering an isotherm in the pressure and temperature phase diagram of an example wet gas/condensate as
illustrated by Figure 2. Starting from the super critical gas region, as the pressure drops isothermally, there is an expansion of
the system volume as the wet gas/condensate transitions from the supercritical gas region to the gas region and finally past
the dew line. When the reservoir fluid undergoes decompression there is a gradual change in the total compressibility of the
reservoir fluid. This can be understood by considering the total isothermal compressibility of the reservoir fluid inside the
PVT cell described by the following equation.
CT  
1  V t 
 ………………………………………………………………………………………………………...…(1)

V t  P 
Where CT is the total isothermal compressibility, Vt is the total volume of the fluid mixture in the PVT cell, and P is the
pressure of the fluid. Above the dew point line the total isothermal compressibility represents the compressibility of the
supercritical gas phase. Below the dew point the total compressibility can be derived using material balance between the gas
and liquid phases. The final derived form of the total compressibility for all stages of compression is represented in the
following expression for the PVT cell.
CT  C G S G  C L S L 
1
Vt
 1
1  m g





G  P
 L

 ………………………………………………………………………......(2)

Where CG is the gas compressibility, SG is the gas saturation in the PVT cell, CL is the liquid compressibility, SL is the liquid
saturation in the PVT cell, ρL is liquid density in the PVT cell, ρG is the gas density in the PVT cell, mg is the mass of the gas
phase of the PVT cell. This expression has important implications at saturation pressure and in the two phase region. For
example, at the dew point of the solution, the first drop of liquid (SL>0) results in a reduction of the gas phase (SG<1). In
addition, the third term in Equation 2 is positive at the dew point since the density of the gas phase is less than the liquid
phase density and the change in gas mass with respect to pressure is negative as a result of the mass transfer of the gas phase
into the liquid phase. This results in a subsequent increase in the total apparent compressibility at the onset of condensation.
At the onset of condensation the liquid volume is extremely small when compared to the gas volume. This can be
seen in the Peng Robinson simulated typical wet gas/condensate (Figure 3).
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SPE 161478
0.3
0.25
Liquid Saturation
0.2
0.15
0.1
0.05
0
0
1000
2000
3000
4000
Pressure, psia
5000
6000
7000
8000
Figure 3: Liquid Saturation for Wet Gas/Condensate system during CCE
In this figure the liquid saturation represents the liquid volume fraction of the total sample volume. A small liquid saturation
corresponds to a small liquid volume. At approximately 5000 psia the liquid saturation is initially 0%. It subsequently
increases to a value of 27% indicating the onset of condensation. During this pressure range, the rate of mass increase in the
liquid phase is negative with pressure and, based on material balance, the rate of mass increase in the gas phase is positive
with pressure. Thereforel, the total compressibility increases according to equation 2. Determining the increase/decrease in
the total compressibility with pressure is the main premise of the method used in this work. When the total compressibility
deviates from the linear compressibility behavior during the CCE process, it is the theorized that this is the dew point
pressure. The general procedure to use the compressibility involves completing the following tasks.
1. Use the CCE experimental data (pressure and volume data) to calculate the central difference approximation of the
compressibility as indicted in Equation 1.
2. Create a plot of the calculated compressibility versus the experimental pressure of the CCE experiment.
3. Starting from the highest pressure of the compressibility versus pressure plot locate the first linear line and draw a
line through it.
4. Find the nearest linear line next to the first linear line and draw a line through it.
5. The intersection between the first and second linear line is the observed dew point.
Experimental Design
To test the new dew point determination method several condensate mixtures were created. These condensate
mixtures include a base condensate mixture with a 1% molar composition of CO2. The other condensate mixtures contained
5%, 10%, and 15% molar concentrations of CO2. The base condensate mixture components can be seen in Table 1. Critical
properties were based on values reported in literature. Acentric factor values were obtained from Winnick (1997) and Poling
et al (2001). Density values were obtained from the API data book. The purpose of using these condensate mixtures was to
understand the effect of adding CO2 to the base concentration and to also illustrate the methodology of the new dew point
determination method.
SPE 161478
5
Table 1: Base Composition for Experimental Studies
Component
Composition,
mol %
Molecular
Weight
Critical
Temperature, oR
Critical
Pressure, psia
Acentric
factor
Methane
83
16.04
343
667
.007
Liquid
Density (60
o
F), lb/gal
2.5
Carbon Dioxide
1
44.01
547.4
1069.5
.225
6.82
Ethane
4
30.07
549.6
706.6
.099
2.97
Propane
3
44.1
665.7
616.1
.153
4.227
Octane
3
114.23
1043.9
422.8
.398
5.894
Dodecane
6
170.34
1215.6
315.3
.576
6.276
To load, mix, and observe the hydrocarbon phase transitions of the proposed condensate mixtures, a pressure,
volume, and temperature (PVT) system (illustrated in Figure 4) was used. As an example of the process used to create and
transfer a mixed condensate, consider the base condensate in Table 1. To calculate the necessary molar amounts of each
component requires determination of the volumetric amount of each component at ambient conditions. At atmospheric
pressure and room temperature the only components that are in the liquid phase are octane and dodecane. The volumetric
amount of these liquid components can be found by using the following equation.
Vi 
MWi y i nt
i
………………………………………………….……………………………………………………...…(3)
Where Vi is the ith liquid component’s feed liquid volume, ρi is the ith liquid component’s density at standard conditions, MWi
is the ith liquid component’s molecular weight, and yi is the ith component’s mole fraction in the gas condensate mixture.
c
b
d
a
e
b
Figure 4: PVT System for Dew Point Measurement (a) Oven (b) Computer Gathering Equipment (c) Top Pump B (d)
PVT Visual Cell (e) Bottom Pump A
The remaining components in the condensate mixture are gases at standard conditions. To feed the required number of
moles of each gas component into the PVT system requires loading the gas components at a target pressure and
corresponding volume. Setting the volume of each gas is much easier to control than pressure, therefore the loading pressure
of each gas component was determined using the Virial equation of state. The following steps can be used to determine the
feed pressure of a component using the Virial equation of state.
1.
2.
Guess a working pressure of the component, Pi, and loading volume of the component, Vi.
For the component, determine the reduced pressure, Pr, and reduced temperature, Tr.
Tr 
T
………………………………………………………………………………………………...………...…(4)
Tc
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SPE 161478
Pr 
3.
P
……………………………………………………………………………………………...………...…(5)
Pc
Where Tc and Pc are the critical temperature and critical pressure of the component.
Calculate the Virial coefficients (Winnick, 1997) using the following equations.
B ( 0 )  0.083  0.422Tr
1.6
B (1)  0.139  0.172Tr
4.2
zi  1 
5.
(1)
Br Pr
…………………………………………………………………………..……….....……..........…(9)
Tr
Recalculate the working pressure, Pi, using the real gas law.
Pi 
6.
………………………………………………………………..………...…….......…(7)
Br  B  B …………………………………………………………………………..………......…….....…(8)
Where ω is the acentric factor of the component.
Calculate the compressibility factor of the component, zi.
( 0)
4.
………………………………………………………………..………...………...…(6)
z i y i nt RT
………………………………………………………………………………………………...…(10)
Vi
Repeat steps 2-5 using the calculated Pi from step 5. Iterate until the value of Pi converges.
The procedure to calculate the feed pressure of each component is based on the Virial equation state and assumes that the
reduced pressure and reduced temperature are within the low density region. This region corresponds to a reduced
temperature and reduced pressure relationship that results in reduced temperatures greater than approximately Tr = .436Pr +
0.6 (Winnick, 1997).
Once the feed liquid quantities and feed gas components are calculated it is important to ensure that the total mixture
can reach system pressures larger than the expected dew point pressure of the condensate system. This is important because
the CCE experiments are begun at pressures much larger than the dew point pressure. Using this assumption, values of the
compressibility factor were calculated using an empirical version of the Standing correlation described by Cronquist (2001)
which is dependent on the pseudo critical properties of the mixed condensate. The pseudo critical temperature and pressure
were calculated using a correlation by Piper et al (1993) which accounts for reservoir impurities such as nitrogen, hydrogen
sulfide, and carbon dioxide. As an example of this process, consider the base condensate listed in Table 1. The phase
diagram of this condensate is illustrated in Figure 5.
Figure 5: Pressure-Temperature Phase Diagram for Base Condensate
From the phase diagram, it can be seen that for a CCE experiment at 200oF, the dew point pressure is approximately 5000
psia. Therefore, at 200oF the initial pressure of the system is set to 6000 psia which is greater than the dew point pressure.
Using this and the volume of the PVT cell it is possible to calculate the total amount of moles that will ensure that the PVT
cell reaches the initial starting pressure. These steps are listed here.
1.
Calculate the gas specific gravity, γg, of the gas condensate sample.
SPE 161478
7
6
 y MW
i
g 
2.
i
29
i
………………………………………………....................................................…….....…(11)
Calculate the pseudo critical temperature, Tpc, and pseudo critical pressure, Ppc, using Piper et al. (1993)
correlation. Assume a pressure larger than the dew point pressure, Pt, and a temperature, Tt, used for the CCE
experiments.
3
T 
2
J   0   f y f  c    4 g   5 g …………………………………………………...……...….…(12)
f 1
 Pc  f
3
 T 
2
K   0    f y f  c    4 g   5 g ………………………………………………...……….…(13)


f 1
 Pc  f
T pc 
Ppc 
K2
……………………………………………………………………………………………......……(14)
J
T pc
J
……………………………………………………………………………………………...…...…(15)
The parameter, f, corresponds to the reservoir fluid impurities in the following order H2S, CO2, and N2. Values
for ηf and βf are shown in the following table.
Table 2: Piper et al (1993) Parameters for Pseudo Critical Temperature Pressure Calculation
f
ηf
βf
0
1.1582E-01
3.8216E+00
1
-4.5820E-01
-6.5340E-02
2
-9.0348E-01
-4.2113E-01
3
-6.6026E-01
-9.1249E-01
4
7.0729E-01
1.7438E+01
5
-9.9397E-02
-3.2191E+00
3.
Calculate the compressibility factor, zt, of the condensate sample at the expected experimental conditions above
the dew point pressure using the Standing correlation (Cronquist, 2001).
Tt
………………………………………………………………………………………...………...…(16)
Tpc
P
Ppr  t ………………………………………………………………………………………...………...…(17)
Ppc
Tpr 
A  1.39T pr  0.92   0.36T pr  0.101 …………………………………………………...………..…(18)
0. 5
6
 0.066
 2
0.32 Ppr
B  0.62  0.23T pr Ppr  
 0.037  Ppr  9
……...……………...…….....…(19)
10 T pr  1
 T pr  0.86

C  0.132  .32 log T pr …………………………………………………...………………………….….…(20)

 0.3106 .49T  0.1824 T
2

pr
pr
D  10
……………………………………………...………………………….….......(21)
D
B
z t  A  1  Ae  CPpr ……………………………………………………………………...……….....(22)
4.
Recalculate the pressure of the cell at the CCE conditions using the expanded volume of the cell, Vt, and the real
gas law.
Pt 
5.
zt nt RTt
…………………...………………………………………………………………………….…(23)
Vt
Repeat steps 3-4 using the calculated Pt from step 4. Keep doing this until the difference between each iterative
Pt is minimized.
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SPE 161478
The preceding procedure is dependent on the total amount of moles, nt, in the PVT cell which is also a necessary component
in the calculation of the volumetric amount of liquid needed and the calculation of the loading pressure for the gas
components. Therefore, any changes made to the total amount of moles in the preceding procedure have to be followed by
recalculations of liquid volumes and gas component loading pressures (at specified loading volumes). As example of these
considerations, consider the base condensate mixture in Table 1. For a CCE experiment at 200 oF (660 oR) for a PVT cell
with 18 cm3 volume (with a value of 100 cm3 out of a possible 200 cm3 of additional adjustable volume used for compression
and expansion) the calculation of the necessary parameters are listed in Table 3 and Table 4.
Table 3: Calculated Liquid Volumes for Base Case
Component
Feed State
Vi, cc
Methane
gas
n/a
Carbon Dioxide
gas
n/a
Ethane
gas
n/a
Propane
gas
n/a
Octane
liquid
6.64
Dodecane
liquid
18.6
Table 4: Gas Calculations for Loading Pressures, Pi, Using Specified Loading Volumes, Vi, for Base Case
Pi
Pi
Component
Feed State
guess,
Tr
Pr
B(0)
B(1)
Br
zi
Vi, cc calculated,
psia
psia
Methane
gas
2698
1.55
0.718 -0.13
0.111
-0.13
0.6687
100
2698
Carbon
gas
48
0.968
0.144 -0.36
-0.0580
-0.37
0.983
100
48
Dioxide
Ethane
gas
176
0.964
0.202 -0.36
-0.0613
-0.37
0.9044
100
176
Propane
gas
125
0.796
0.124
-0.52
-0.309
-0.57
0.8547
100
125
Octane
liquid
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Dodecane
liquid
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
Table 5: Parameters used to calculate .003 total lbmols needed to reach 6000 psig at 200oF (Volume used for
calculation is 118 cc)
ɣg
1.03
J
0.736
K
18.3
o
Tpc, R
457
Ppc, psi
621
Tpr
1.16
Ppr
9.67
A
0.163
B
20.5
C
0.111
D
0.972
zt
1.17
Pt, psig
6000
The total amount of moles needed to bring the system to 6000 psig was found to be 0.003 lbmol. This quantity is verified
because it can be used to calculate the 6000 psig desired pressure at 200 oF and 118 cc of available volume (Table 5). This
quantity was also found to satisfy the procedure of determining the gas loading pressures (Table 4) and the required liquid
volumes (Table 3).
SPE 161478
9
Experimental Results
Dew points were determined for the synthetically designed condensate mixtures by observing changes in
compressibility from constant composition expansion experiments and verified by equation of state models such as Peng
Robinson equation of state. As an example of the process of using the compressibility to determine the dew point pressure,
consider the 15% CO2 case at 200 oF. Its CCE isotherm (Figure 6) illustrates the pressure volume relationship for this fluid.
The total compressibility of this fluid was calculated for each pressure point (Figure 7) using a central finite difference
version of Equation 1.
15% CO2 in Base: Pressure versus Volume at 200 oF
7000
6000
Pressure, psia
5000
4000
3000
2000
1000
0
50
55
60
65
70
75
Volume, cc
80
85
90
Figure 6: CCE isotherm for 15% CO2 in Base Case at 200 oF
95
100
10
SPE 161478
15% CO2 in Base: Compressibility versus Pressure at 200oF
0.0006
Compressibility, 1/psi
0.0005
0.0004
0.0003
0.0002
3116.7 psia
0.0001
0
0
1000
2000
3000
4000
Pressure, psia
5000
6000
7000
Figure 7: Dew Points Determination using compressibility versus pressure plot for 15% CO2 in Base Case at 200 oF
Figure 7 illustrates a substantial increase in the compressibility at approximately 3117 psia. This large increase is attributed
to the first instance of liquid saturation in the PVT cell. According to Equation 2, the first appearance of liquid saturation and
volume can cause substantial increases in the total compressibility. Using this large rise in compressibility, the dew point for
the 15% CO2 case is approximately 3117 psia.
The compressibility methodology was applied to the Base case, 5% CO2 case, 10% CO2 case, and the15% CO2
case. Results of the dew point measurement of each case can be seen in Table 6 and Figure 8.
Table 6: Comparison of Dew Point Measurements at 200oF
New Method, psia
Peng Robinson, psia
Absolute Error, %
Base Case
5627
5000
13
5% CO2 in Base
3548
4800
26
10% CO2 in Base
3530
4600
23
15% CO2 in Base
3117
4400
29
SPE 161478
11
6000
5500
Pressure, psia
5000
4500
4000
3500
3000
2500
2000
0
2
4
6
Peng Robinson
8
10
CO2 mol%
12
14
16
Compressibility Method
Figure 8: Dew Point Comparison as Function of CO2 Concentration in Base Composition at 200oF
When comparing the dew point measurement among each case at 200 oF it can be seen that CO2 has the unique ability in
reducing the dew point pressures. This is observed experimentally in Figure 8 and Figure 9 which is a plot of the relative
volume (PVT volume divided by the volume at the dew point).
7000
6000
Pressure, psia
5000
4000
3000
2000
1000
0
0
0.2
0.4
Base Case
0.6
0.8
1
1.2
Relative Volume,
5% CO2 in Base
10% CO2 in Base
1.4
1.6
1.8
15% CO2 in Base
Figure 9: Experimental Relative Volume of Base Condensate as function of CO2 at 200oF
2
12
SPE 161478
The relative volume plot in Figure 9 indicates that CO2 decreases the corresponding pressures observed during CCE. The
Peng Robinson approximation of the relative volume, as illustrated by Figure 11, indicates the same relationship. In addition
to this, the overall phase diagram of the gas condensate illustrates that the phase envelope decreases as a function of CO2
concentration. This is conveyed in Figure 10. These results can be explained by analyzing previous studies of CO2 with
hydrocarbon systems. Monger et al. (1981) were able to illustrate in their Appalachian crude oil system that the crude oil
aromaticity correlated with improved hydrocarbon extraction into a CO2 rich phase. In addition to this, Monger et al.
observed that CO2 has the ability to lower miscible pressures for paraffin fluids that do not contain large amount of aromatic
content. In terms of gas condensate systems, this means that CO2 forces the lighter end hydrocarbons into the CO2 rich
phase. This is beneficial because the CO2 rich phase is a supercritical gas in typical reservoir conditions which implies that
CO2 is lowering the hydrocarbon’s dew point pressure.
6000
5000
Pressure, psia
4000
3000
2000
1000
0
300
400
500
600
700
Temperature, oR
800
900
Base Condensate
5% CO2
10% CO2
15% CO2
Base Condensate Critical Point
5% CO2 Critical Point
10% CO2 Critical Point
15% CO2 Critical Point
1000
660oR (200oF) Isotherm
Figure 10: Peng Robinson Phase envelope of gas condensate as function of CO2 concentration
SPE 161478
13
8000
7000
Pressure, psia
6000
5000
4000
3000
2000
0.6
0.8
Base
1
1.2
1.4
Relative Volume,
5% CO2 in Base
1.6
10% CO2 in Base
1.8
2
15% CO2 in Base
Figure 11: Peng Robinson Relative Volume of Base Condensate as function of CO2 at 200oF
In terms of liquid compressibility, the Peng Robinson approximation of the liquid saturation during CCE (Figure 12) gives an
indication that there is less liquid dropout occurring as the amount of CO2 increases. In regards to production from gas
condensate reservoirs, this is beneficial because this shows that increasing the CO2 concentration can decrease the maximum
amount of liquid saturation that can occur in the reservoir.
0.3
0.25
Liquid Saturation
0.2
0.15
0.1
0.05
0
0
1000
Base
2000
3000
5% CO2 in Base
4000
Pressure, psia
5000
10% CO2 in Base
6000
7000
8000
15% CO2 in Base
Figure 12: Peng Robinson Liquid Saturation of Base Condensate as function of CO2 at 200oF
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SPE 161478
Retrograde Behavior
In determining dew points using compressibility it is important to also consider the possibility of lower dew points
which are indicative of retrograde reservoir fluid behavior. The lower dew point can be found using the compressibility
method by noticing sharp deviations in the compressibility slope after determination of the upper dew point. Understanding
the reason that this happens can be understood by first considering the empirical definition of compressibility as indicated by
Equation 2. At the lower dew point the liquid saturation disappears (SL = 0) leaving room for the more compressible fluid
which is gas to define the total compressibility. Gases respond to small decreases in pressure with sudden increases in
compressibility. In the case of retrograde fluids this means that the second change in slope is the sharp rise in compressibility
representative of single phase gas behavior. An example of this can be seen for the 10% CO2 in the Base case as illustrated
by Figure 13.
10% CO2 in Base: Compressibility versus Pressure at 200 oF
0.0007
0.0006
Compressibility, 1/psi
0.0005
0.0004
0.0003
Lower Dew Point =
2344.7 psia
0.0002
Upper Dew Point =
3529.7 psia
0.0001
0
0
1000
2000
3000
4000
Pressure, psia
5000
6000
7000
Figure 13: Lower Dew Point Determination using compressibility plot for 10% CO2 in Base Case at 200 oF
From the plot there is a clear distinction between different slopes. The first change in slope represents the transition from the
super critical region to the two phase region. The second change in slope represents the transition from the two phase region
to the gas region which is indicative of retrograde behavior. This retrograde behavior represents possible errors associated
with preparing the 10% CO2 wet gas sample but provides valuable information regarding compressibility behavior of
retrograde systems.
Conclusions
The general conclusions are the following:
1. The compressibility method can be used to discern the onset of liquid saturation. This method relies on
distinguishing between changes in slope in compressibility versus pressure plots. The compressibility method
is dependent on the assumption that small amounts of liquid at the onset of condensation can cause increases in
liquid compressibility which conversely increases the total compressibility.
2. CO2 has the unique ability of reducing the dew point of gas condensates. This is evident when observing the
experimental and Peng Robinson approximation of the relative volume. This is also evident when analyzing the
Peng Robinson approximation of the pressure temperature diagram which illustrates that CO2 reduces the phase
envelope.
3. CO2 can reduce liquid dropout. This is beneficial because it can reduce liquid blockage in the near well bore
region for wet gas wells that have significant liquid drop out.
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15
Nomenclature
CT = total isothermal compressibility
Vt = total volume of the PVT cell
P = pressure of the PVT cell
CG = gas compressibility
SG = gas saturation
CL = liquid compressibility
SL = liquid saturation
VL = liquid volume
Vi = ith liquid component’s feed liquid volume
ρi = ith liquid component’s density at standard conditions
MWi = ith liquid component’s molecular weight
yi = ith component’s mole fraction in the gas condensate mixture
Pi = loading or working pressure of the ith component
Vi = loading volume of the ith component
Pr = reduced pressure
Tr = reduced temperature
B(0) = virial equation coefficient
B(1) = virial equation coefficient
Br = virial equation parameter
ω = acentric factor of the component
zi = compressibility factor of the ith component
γg, = specific gravity of the gas condensate sample
Tpc = pseudo critical temperature
Pt = pressure larger than the dew point pressure
Tt = temperature used for the CCE experiments
Ppc = pseudo critical temperature
J = parameter in Piper et al correlation
K = parameter in Piper et al correlation
ηf = parameter in Piper et al correlation
βf = parameter in Pier et al correlation
A = parameter in Standing correlation
B = parameter in Standing correlation
C = parameter in Standing correlation
D = parameter in Standing correlation
zt = total compressibility factor for condensate mixture
ρL = liquid density in the PVT cell
ρG = gas density in the PVT cell
mg = mass of the gas phase of the PVT cell
Acknowledgement
This paper was made possible by NPRP grant # 4-007-2-002 from the Qatar National Research Fund (a member of
Qatar Foundation). The statements made herein are solely the responsibility of the author.
References
1. Winnick, Jack. 1997. Chemical Engineering Thermodynamics. John Wiley & Sons, Inc. pp 86-95 and pp 554-556.
2. Cronquist, Chapman. 2001. Estimation and Classification of Reserves of Crude Oil, Natural Gas, and Condensate.
Society of Petroleum Engineers. pp 311-312.
3. Piper, L.D., McCain, W.D., and Holditch, S.A. 1993. Compressibility Factors for Naturally Occurring Petroleum
Gases. Paper SPE 26668 presented at the 68th Annual Technical Conference and Exhibition of the Society of
Petroleum Engineers, Houston, TX, 3-6 October.
4. Firoozabadi, Abbas. 1999. Thermodynamics of Hydrocarbon Reservoirs. McGraw-Hill. pp 165-169.
5. Whitson, C.H. and Kuntadi, A. 2005. Khuff Gas Condensate Development. Paper IPTC 10692 presented at the
International Petroleum Technology Conference. Doha, Qatar, 21-23 November 2005.
6. Poling, B., Prausnitz, J., and Oconnell, J. 2001. The Properties of Gases and Liquids Fifth Edition. McGraw-Hill.
pp. A.17
7. API Technical Data Book. new.api.org
8. Potsch, K.T. and Braeuer, L. 1996. A Novel Graphical Method for Determining Dewpoint Pressures of Gas
Condensates. Paper SPE 36919 presented at the European Petroleum Conference. Milan, Italy, 22-24 October
1996.
16
SPE 161478
9.
Monger. T.G. and Khakoo, A. 1981. The Phase Behavior of CO2- Appalachian Oil Systems. Paper SPE 10269
presented at the 56th Annual Fall Technical Conference and Exhibition. San Antonio, TX, 5-7 October.
Appendix
Base Case: Pressure versus Volume at 200 oF
7000
6000
Pressure, psia
5000
4000
3000
2000
1000
0
20
22
24
26
Volume, cc
28
Figure 14: CCE isotherm for Base Case at 200 oF
30
32
SPE 161478
17
Base Case: Compressibility versus Pressure at 200 oF
0.00035
0.0003
Compressibility, 1/psi
0.00025
0.0002
0.00015
0.0001
5626.7 psia
0.00005
0
0
1000
2000
3000
4000
Pressure, psia
5000
6000
7000
Figure 15: Dew Points Determination using compressibility versus pressure plot for Base Case at 200 oF
5% CO2 in Base: Pressure versus Volume at 200 oF
4000
3500
3000
Pressure, psia
2500
2000
1500
1000
500
0
0
20
40
60
80
100
Volume, cc
Figure 16: CCE isotherm for 5% CO2 in Base Case at 200 oF
120
140
18
SPE 161478
5% CO2 in Base: Compressibility versus Pressure at 200 oF
0.002
0.0018
0.0016
Compressibility,1/psi
0.0014
0.0012
0.001
0.0008
0.0006
3547.7 psia
0.0004
0.0002
0
0
500
1000
1500
2000
Pressure, psia
2500
3000
3500
4000
Figure 17: Dew Points Determination using compressibility versus pressure plot for 5% CO2 in Base Case at 200 oF
10% CO2 in Base: Pressure versus Volume at 200 oF
7000
6000
Pressure, psia
5000
4000
3000
2000
1000
0
60
70
80
90
Volume, cc
100
110
Figure 18: CCE isotherm for 10% CO2 in Base Case at 200 oF
120
SPE 161478
19
10% CO2 in Base: Compressibility versus Pressure at 200 oF
0.0007
0.0006
Compressibility, 1/psi
0.0005
0.0004
0.0003
0.0002
3529.7 psia
0.0001
0
0
1000
2000
3000
4000
Pressure, psia
5000
6000
7000
Figure 19: Dew Points Determination using compressibility versus pressure plot for 10% CO2 in Base Case at 200 oF