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