HOPE MEYERS
Rock and Fluid Laboratory
Fluid Saturations
Relative Permeability
Gas Compressibility Factor
Energy and Mineral Engineering Department
The Pennsylvania State University
April 14, 2011
Table of Contents
Executive Summary
There were a total of three experiments conducted in this final section of the lab.
They all coincided with each other because they all dealt with fluid factors, and how
fluids affected saturation, permeability, and compressibility. Because fluids can act in
different ways, we studied how gases compared with liquids deviated from normal
behavior.
In experiment five, titled Fluid Saturations, we determined the amount of oil and
water in a sandstone sample by solvent extraction method, and by the retort method. In
the solvent extraction method the volume of water in the core is determined by
vaporizing and condensing the water. The water is then received by a graduated receiver.
The oil is taken out of the core with a solvent. From the solvent extraction method, very
little water was condensed and the core sample was mostly saturated by oil. There was
very minimal gas saturation that was calculated after all the values were obtained. In the
retort method the liquids from the core sample were vaporized and then condensed. The
core is placed in a retort holder, heated, and the liquids are collected in a small graduated
cylinder so the oil and water can be read. From the retort method, there was more water
saturation than in the solvent extraction method. The gas saturation was very small, and
the oil saturation was the largest.
In experiment six, titled Relative Permeability, we measured the relative
permeabilities of oil and water in a core sample. Core samples from previous experiments
that were saturated with water were used. We used a method called drainage, in which oil
was injected into the sample until the whole sample was completely saturated with oil
and all the water was evacuated. We also used imbibition, in which water was injected
into the sample until all the oil was evacuated. Using these two methods, we could
determine the permeability of the sample with respect to water, and oil.
In experiment seven, titled Gas Compressibility Factor, we observed and
quantified the pressure, volume, and temperature nature of an imperfect gas through
measurements of the Z factor as a function of pressure, at a specific temperature. The Z
factor is a correction factor that accounts for the non-ideality of a gas. So, instead of the
ideal gas equation PV=nRT, the equation becomes PV=ZnRT. Through this experiment,
we found that the Z factor is evident in non-ideal gases.
Introduction
In the Fluid Saturations experiment, a sandstone sample that was saturated with
oil and water was used in order to conduct two methods of fluid extraction known as solvent
extraction, and retort method. These methods can both be used to determine the amount of
saturation of a specific fluid. The solvent extraction method is where the volume of water is
obtained by vaporizing the water, and then the water condenses into a water trap to be
measured. The oil is extracted from the sample using a solvent, in this case, toluene. Using
initial measurements and calculations through the experiment, the saturations of oil, water,
and gas can be found. In the retort method a saturated core sample is placed in a retort holder,
which is then heated at a high temperature. The fluids that saturated the sample are driven off
the sample by the heat, and collected in a graduated cylinder that is placed under the retort
holder. Since the oil and water are collected together, they will separate in the graduated
cylinder and the measurements can be read. These are important methods because when
reservoirs are found, they usually do not only contain oil. They usually contain water, oil,
and gas because hydrocarbons go from source rocks into porous reservoir rocks. If there is a
highly permeable and highly porous rock, it is imperative to be able to determine how much
oil, or if there is oil at all in the rock. If there is a substantial amount of oil available in a
rock, then it would be beneficial to extract it. This is why being able to know the saturation
of different rocks is especially important to petroleum engineers. If we did not know how to
do this, we would be undoubtedly performing wasteful tasks in order to extract oil.
In the Relative Permeability experiment, the relative permeabilities of oil and
water in a core sample were measured. Permeability is a quality of the rock, and not of the
fluid that is flowing through the rock. Permeability is the ease with which a fluid can flow
through the pores of a rock. What makes this experiment important is that we are dealing
with oil and water flowing through a rock sample, which can alter the permeability of the
rock. When more than one fluid is present in a rock, it makes the flow characteristics
different and we have to account for that difference. This is where effective permeability is
used, which is when a porous material conducts a fluid when the saturation of that fluid is not
at 100%. Relative permeability is the effective permeability of a fluid with respect to the
permeability of the fluid at 100% saturation. To determine the various permeabilities of the
rock sample, we conducted drainage, which is oil injection into the rock, as well as
imbibition, which is water injection into the rock. Using both of these methods aided in
finding permeabilities.
In the Gas Compressibility Factor experiment, the pressure, volume, and
temperature nature of an imperfect gas was observed and quantified through measurements
of the compressibility factor, Z, as a function of pressure, as a specific temperature. High and
low pressure vessels were used, as well as heated and cooled vessels in which to submerse
the high pressure vessels. The ideal gas law, PV=nRT, works for ideal gases, meaning gases
that are at low pressure and high temperature. When gases are not at ideal conditions, the
ideal gas law does not give correct calculations and a correction factor needs to be in place in
order to give us accurate results. The correction factor in this case is known as the
compressibility factor, Z. The compressibility factor is used when gases are not ideal, or at
high pressures and low temperatures. Z compensates for the non-ideal characteristics that are
in place, so the real gas law is used as PV=ZnRT. This factor is very important because using
the ideal gas law for a non-ideal gas would give completely miscalculated errors that would
lead to misconstrued ideals for gases.
Results and Discussion
Fluid Saturation Lab
In the Fluid Saturations lab, a saturated core sample was measured, and the fluids were
extracted for measurement. In the first concept used, which was the solvent extraction method, a
solvent was used in order to aid the extraction process. The water that condensed was measured,
while the volume of the oil had to be calculated using the change in weights, and the properties
of water and oil densities. With the volume of the oil and water known, as well as the pore
volume, the saturations of the water, oil, and gas could be found. The following tables show the
measurements and calculations that were found using the solvent extraction method.
Porosity 0.234Weight of saturated simple 42.28 gDensity of oil 0.81 g/cc
Density of water 1.00 g/ccVolume of water collected 0.1 ccWeight of dry sample 39.3 gOriginal weight of fluids (∆Wt) 2.98 gBulk volume 15.61 cc
Volume of oil 3.56 cc
Pore volume 3.66 cc
Oil saturation 0.973Water saturation 0.027Gas saturation 0.000
The second method that was used, the retort method, involved a retort holder which
heated the saturated core sample in order to extract the liquids. When the core sample was
heated, a small graduated cylinder was placed under the retort holder to catch the oil and water
mixture that fell from the core. After waiting for a substantial amount of time, all the liquids
were removed and were separated in the cylinder. The values could be read directly, and the
measurements and calculated volumes are shown in the following tables.
Porosity 0.257Weight of saturated sample 35.94 gVolume of oil collected 2.4 ccCorrected oil volume 3 ccVolume of water collected 0.6 ccWeight of dry sample 33.2 g
Bulk volume 14.02 ccPore volume 3.6 cc
Oil saturation 0.833Water saturation 0.166Gas saturation 0.001
In this experiment, the solvent extraction method and retort method were both effective.
The solvent extraction method gave values for the core sample which had the most oil saturation,
very little water saturation, and no gas saturation. The retort method gave values for the core
sample which had significant oil saturation, small water saturation, and very minimal gas
saturation. These methods are effective in finding the saturations of different fluids in a core
sample, but the process takes a lot of time. Considering we live in a fast paced society, these
methods are useful, but very time consuming. Although these values were calculated for the core
samples, both samples that were used for the two methods were different. I think the findings for
this experiment would have been more successful if the core samples were exactly the same, and
saturated with the same fluids for the same amount of time. This way, we would be able to see
which method worked the best in finding the saturations of fluids. Some errors that could have
occurred in this experiment were the time that we used to conduct the experiment. In the lab
manual, it says that for the solvent extraction method the system should be left in place for two
hours in order to have the best results. We left our system in place for less than two hours, which
definitely could have caused some error. For the retort method, the cooling process of the core
sample was supposed to be over night, where as we came back a few hours after the experiment
to take measurements of our sample.
Relative Permeability Lab
In the Relative Permeability lab, the relative permeabilities of oil and water were
measured in a core sample. First, drainage was used which is oil injection. The core sample was
already saturated with water from a previous experiment, and the oil was placed in a beaker at a
height of 25.7 inches and the oil gradually pushed the water out of the sample. The sample
became fully saturated by oil. The following data table shows the values that were used to
conduct the drainage method.
Time interval (s)
Cum. Time (s)
Produced Vwater (cm3)
Cum. Vwater (cm3)
Produced Voil (cm3)
Sw (%) So (%)
120 120 14 14 0 89.2 10.8120 240 12 26 0 80 20120 360 10 36 0 72.3 27.7120 480 9 45 0 65.4 34.6120 600 7 52 0 60 40120 720 6 58 0 55.4 44.6120 840 6 64 0 50.8 49.2120 960 5 69 0 46.9 53.1120 1080 4.6 73.6 0 43.4 56.6120 1200 4.2 77.8 0 40.2 59.8120 1320 4 81.8 0 37.1 62.9120 1440 3.8 85.6 0 34.2 65.8120 1560 3.6 89.2 0 31.4 68.6120 1680 3.4 92.6 0 28.8 71.2120 1800 3.2 95.8 0 26.3 73.7120 1920 3.2 99 0 23.8 76.2120 2040 3 102 0 21.5 78.5120 2160 2.8 104.8 0.2 19.4 80.6120 2280 2.6 107.4 0.6 17.4 82.6120 2400 2 109.4 1 15.8 84.2120 2520 1 110.4 2.2 15.1 84.9120 2640 0.6 111 3 14.6 85.4120 2760 0.4 111.4 3.2 14.3 85.7120 2880 0 111.4 3.8 14.3 85.7
The following graph shows the saturation of water with respect to time, when the
drainage method was used. In the beginning, the saturation of water was very high, but as the oil
was gradually injected into the sample, the saturation of water decreased.
0 500 1000 1500 2000 2500 3000 35000
102030405060708090
100Saturation of Water VS Time (Drainage)
Series2
Time (s)
Satu
ratio
n (%
)
The following chart shows the flow rate of water with respect to the water saturation.
When the flow rate is low, the water saturation is low as well and when the flow rate is high, the
water saturation is high. This is true because when the oil is injected, the flow rate of water
decreased, and the saturation of the water decreased as well since the sample was becoming more
saturated with oil.
10 20 30 40 50 60 70 80 90 100012345678
Flow Rate VS Water Saturation
Series2
Saturation (%)
Flow
Rat
e (c
c/m
in)
Imbibition was the next method used, which is water injection. When the sample became
fully saturated with oil, we then repeated the same process except this time we used water to
push all the oil out of the system. We placed the beaker higher up this time, at a height of 44.35
inches. The height was increased to speed up the rate of the experiment. The following table
shows the values that were used and found while conducting the imbibition.
Time interval (s)
Cum. Time (s)
Produced Vwater
(cm3)
Cum. Vwater (cm3)
Produced Voil (cm3)
Cum. Voil
(cm3)Sw (%) So (%)
120 120 0 0 5.6 5.6 2.5 95.7120 240 2.2 2.2 9.8 15.4 11.8 88.2120 360 1.6 3.8 9.4 24.8 19.1 80.9120 480 0.8 4.6 9.2 34 26.2 73.8120 600 0.6 5.2 11.4 45.4 34.9 65.1120 720 0.4 5.6 12.6 58 44.6 55.4120 840 0.2 5.8 14.8 72.8 56 44120 960 4.0 9.8 12 86.8 66.8 33.2120 1080 18.5 28.3 3.5 90.3 69.5 30.5120 1200 21.0 49.3 1.0 91.3 70.2 29.8120 1320 22.5 71.8 0.5 91.8 70.6 29.4120 1440 21.8 93.6 0.2 92 70.8 29.2120 1560 23.0 116.6 0 92 70.8 29.2
The following graph shows the saturation of water with respect to time for the imbibition
method. Since the sample was almost completely saturated with oil at the beginning, the
saturation of water was minimal. As the water was injected into the system the saturation of
water increased.
0 200 400 600 800 100012001400160018000
10
20
30
40
50
60
70
80 Saturation of Water VS Time (Imbibi-tion)
Series2
Time (s)
Satu
ratio
n (%
)
The following graph shows the flow rate of the water coming out of the sample
with respect to the water saturation. The flow rates that we recorded were not very consistent,
which is visible in the graph. If we had more regular flow rates, the graph would show that as the
flow rate increased, the water saturation would increase as well.
0 10 20 30 40 50 60 70 800
0.20.40.60.81
1.2
Flow Rate VS Water Saturation
Series2
Saturation (%)
Flow
Rat
e (c
c/m
in)
The saturation percentages of the water and oil were found by using the pore volume of
the core sample, the water produced, as well as the oil produced. When I looked back at the
previous lab to find the pore volume of the core sample, it was 73.93 cc. By looking at the values
recorded in the previous tables, it is easy to see that this value was incorrectly calculated.
Professor Karpyn and I discussed the values that were found in this lab, and collectively
estimated a new pore volume for this experiment which was estimated to be 130 cc. This value
proved to be efficient in the data process, and gave sufficient results. This section is very
important because many times oil is not the only fluid that is present in a rock. Water and gas are
usually present as well, and the saturations of these fluids determine whether one should drill to
extract oil or not. Some possible errors in this experiment were the saturations of the samples.
Initially, they were saturated with water but the saturation may not have been sufficient. Also,
during drainage and imbibition not all of the previous fluid was pushed out of the system,
causing some error in the relative permeabilities. Using a beaker and essentially gravity as means
of drainage and imbibition made the experiment long and tedious, and probably not completely
accurate.
Gas Compressibility Factor (Z)
In the Gas Compressibility Factor experiment, the nature of gas was observed while at
non-ideal temperatures and pressures. When a gas is at high pressure and low temperature, the
conditions are not ideal which means a compressibility factor, denoted as Z, must be used to
compensate for the non-ideal nature of the gas. The Z factor was tested at hot and cold
temperatures using methane gas. The following chart shows the initial factors that were used in
the experiment to help calculate the Z factor, as well as the moles in the experiment. The
temperature of these values was the hot temperature.
Test Gas Methane
Room Temperature 60 degrees C
Room Pressure 1 atm
Volume of large tank 511.85 cc
Volume of small tank 151.3 cc
Fittings volume 5.2 cc
Cell temperature 78 degrees F
With the previous values listed in the table, as well as findings during the experiment, the
following table was created showing the moles bled off from the small tank to the large tank, the
cumulative number of moles, and the number of moles remaining in the small tank as well as the
Z factor. These values were calculated from the high temperature experiment.
Pressure
small tank
(psig)
Pressure large
tank (psig)
N moles bled
off
Cumulative n
moles bled
N remaining
in small tank
Z factor
490 0 0.02 0.02 0.244 0.87
455 0 0.02 0.04 0.224 0.88
417 0 0.017 0.057 0.204 0.89
385 0 0.019 0.076 0.187 0.9
350 0 0.035 0.111 0.168 0.91
275 0 0.017 0.128 0.133 0.915
240 0 0.017 0.145 0.116 0.92
205 0 0.018 0.163 0.099 0.93
167 0 0.018 0.181 0.081 0.94
130 0 0.018 0.199 0.063 0.96
90 0 0.016 0.215 0.045 0.97
52 0 0.016 0.233 0.029 0.98
12 0 0.018 0.238 0.011 0.99
0 0 0.005 0.238 0.006 1
The following table shows the initial values that were given or read at the beginning of
the experiment. These values coincide with the cold temperature that was tested for the Z factor.
Test Gas Methane
Room temperature 60 degrees F
Room Pressure 1 atm
Volume of large tank 506.7 cc
Volume of small tank 151.3 cc
Fittings Volume 5.2
Cell temperature 64 degrees F
The following table shows the values given, read, and calculated from the cold
temperature experiment section. The pressure of the small tank was charged so that it had high
pressure, and a low temperature. The pressure of the small tank and the large tank were then
equalized, while moles bled from the small tank to the large tank. These values were calculated
using PV=nRT and the Standing and Katz factor chart.
Pressure
small tank
(psig)
Pressure large
tank (psig)
N moles bled
off
Cumulative n
moles bled
N remaining
in small tank
Z factor
590 0 0.022 0.022 0.314 0.83
555 0 0.021 0.043 0.292 0.84
520 0 0.02 0.063 0.271 0.85
485 0 0.021 0.084 0.251 0.86
450 0 0.018 0.102 0.230 0.87
415 0 0.019 0.121 0.212 0.875
380 0 0.021 0.142 0.193 0.88
345 0 0.018 0.16 0.172 0.9
310 0 0.019 0.179 0.154 0.91
275 0 0.015 0.194 0.135 0.925
245 0 0.017 0.211 0.120 0.93
210 0 0.018 0.229 0.103 0.94
175 0 0.016 0.245 0.085 0.96
140 0 0.018 0.263 0.069 0.965
100 0 0.016 0.279 0.051 0.97
65 0 0.018 0.297 0.035 0.98
25 0 0.011 0.308 0.017 0.99
0 0 0 0.308 0.006 1