master thesis miaad

7/30/2019 Master Thesis Miaad

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DECLARATION (12 pt bold)

The substance of this thesis is original work of the author and due reference and

acknowledgement has been made, whenever necessary, to the work of others cited in this

thesis. No part of the thesis has been submitted or accepted for any degree at the PetroleumInstitute or at any other institution worldwide and is not concurrently submitted or will besubmitted in candidature for any other degree.

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Candidates name and signature with dateAll 12 pt Times New Roman; double space; top margin = 3.5 inch


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FULL THESIS/REPORT TITLE HERE

IN CAPS, TIMES NEW ROMAN, BOLD

Thesis Approved

______________________________________

__ Thesis Adviser, 12 Pt Normal, Times NewRoman

_______________________________________Committee Member

_____________________________________

Committee Member

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Department Chair

_____________________________________Dean of Graduate School_____________________________________

Acting President and Provost

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ACKNOWLEDGEMENT (12 pt bold) -- optional

This Masters Thesis is dedicated to Used to acknowledge those who have supported you

during your graduate studies. This is not typically the place to recognize those who assisted

you in your academic research. That is done on the required Acknowledgements page


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Abstract


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Table of content

ACKNOWLEDGEMENTS................................................................................................ iiLIST OF Figures ............................................................................................. ivLIST OF TABLES...............................................................................................................v

LIST OF ABBREVIATIONS/NOTATIONS.................................................................... vi

ABSTRACT......................................................................................................................

Chapter 1: Introduction

Chapter 2: Review of literature

2.1 Background

2.1.1 Fluid rock interaction

2.1.2 Velocity analysis and petrophysics properties correlation

2.1.3 Images analysis to study rock texture?

2.1.4 Importance of fluid analysis??

2.2 Summary of Previous Research

2.3 Defining the Research Topic

Chapter 3: Investigation methods and principles

3.1 Images analysis

Thin Section

SEM

3D-images

3.2 (Acoustic )Velocities or (Vp and Vs)

3.3 Porosity and permeability

3.4 ICP fluid analysis


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Chapter 4: Experimental work (Experiments)

Chapter 5: Results

5.1Sample C17

5.1.1 Images analysis

Thin Section

SEM

3D-images

5.1.2 Acoustic Velocities (Vp and Vs)

5.1.3 Porosity

5.1.4 Permeability

5.1.5 ICP fluid analysis

5.2 Sample D19


Thin Section

SEM

3D-images

5.2.2 Acoustic Velocities (Vp and Vs)

5.2.3 Porosity

5.2.4 Permeability


Chapter 6: Analysis

6.1 Sample C17

6.2 Sample D19

6.3 Comparison between Sample C17 and D19

6.4 Comparison with previous studies

6.5 Implication


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Chapter 7: Conclusion

Chapter 8: Recommendation and further work

Chapter 1: Introduction

Carbonate sediments are the most common hydrocarbon reservoirs in the world;

representing 60% of the total reservoirs (Gosh and Sen, 2012). Characterization of

carbonate reservoir is considered to be very complex due to lack of research in rock

physics of carbonate rocks (Vanorio and Mavko, 2011) and carbonate reservoirs

heterogeneity. Carbonate aquifers are also difficult to characterize due the carbonate

heterogeneity. Carbonate reservoirs and aquifers are mostly affected by diagenesis

processes such as compaction, dissolution, precipitation and cementation (Assefa et

al., 2003 and Koesoemadinata and George, 2003). Diagenetic processes, affecting

carbonate rocks can be reactivated during the production as a result of fluid-rock

interaction.

In the case of primary oil recovery, (i.e. without external fluids injected in the rock),

the induced flow and pressure may introduce some changes in the original porosity

and permeability. Whereas, when injecting external fluids in the rock, for example to

enhance production, this process might introduce a disequilibrium in the host rock

system that can lead to physical and chemical changes in the reservoir (Vialle and

Vanorio, 2011). In the case of carbonate aquifers, similar concept is applied during

the production. During the production from the aquifers the induced flow and

pressure may introduce some changes in the original porosity and permeability. These


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physical and chemical changes might lead to changes to porosity () and

permeability (

The aim of the research is to better understand fluid-rock interaction in carbonate

rocks that lead to porosity and permeability variation as a result of potential changes

in producing hydrocarbon and/or water reservoirs. In this study we test the ability of

detecting porosity and permeability changes using acoustic velocities (Vp and

Vs).This research might contribute to oil and gas industry and to hydrology study of

aquifers by improve the understanding of how fluid-rock interaction would affect

reservoir quality. Consequently, this might help in monitoring hydrocarbon

production in carbonate reservoir and hydrological study of carbonate aquifers .

Chapter 2: Review of literature

2.1 Background

2.1.1 Fluid rock interaction

2.1.2 Velocity analysis and petrophysics properties correlation

2.1.3 Images analysis to study rock texture?

2.2 Defining the Research Topic

Two main objectives are identified for this study. First objective is to investigate a

potential correlation between fluid-rock interaction, and porosity permeability changes.

The motivation of this objective is draw a clear understanding about this correlation since

previous reviewed studies has some limitations as mention in literature review section.

For example Vega's et al. (2011) study show small changes in porosity that might be due

to fluid rock interaction, whereas the permeability was not considered. Vega's study was


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carried in a pure mineral which is not a good representation of a real carbonate reservoir/

carbonate aquifers, so repeating experiment with the carbonate samples might add

significance value to reservoir characterization. Vialle and Vanorio experimental study

also show a potential correlation between fluid-rock interaction and porosity and

permeability changes. However, Vialle and Vanorio study was focusing mainly in a

mudstone samples without considering petrophysical properties variation in real reservoir

rock. In my study, I choose two samples that are slightly differ in term of pertophysical

properties.

One of the tested hypotheses in this part is the ability of geochemistry and sample

imaging analysis in improving the investigating fluid rock interaction mechanism.

Second main objective of this study is to test the applicability of detecting porosity and

permeability changes by acoustic velocity laboratory scale (high frequency wave). An

important hypothesis to be tested in this study is the ability of acoustic velocities in

detecting porosity and permeability changes at laboratory scale.

Chapter 3: Investigation methods and principles

3.1 Images analysis

Thin Section

SEM

3D-images and image processing using Sakhr program

3.2 Porosity and permeability

3.3 (Acoustic )Velocities or (Vp and Vs)

3.4 ICP fluid analysis


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Chapter 4: Experimental work (Experiments)

In order to accomplish the research objectives several steps were followed as shown in

Figure 2

Figure 2: Procedure followed in research

4.1 Sample selection

Two reservoirs samples were selected from set of samples that we have in rock physics

lab. The samples are from . Field, Thamama zone??). In total we have 58 samples from

four different wells. Initially 10 samples were selected from 56 recorded samples in the

data sheet. The selection first was depending on samples availability since most of the

samples were already in use for another experiment and others are used as test samples

for equipment calibration on the lab. From the 10 available samples I choose four

samples that can be used for experimental purposes. The remaining six samples were

either destroyed or not applicable for experimental purposes since they are very small

(with an approximate length of 6 cm). In addition to that, most important criteria that

restrict my choices are the petrophyiscal properties which are Klinkenberg-corrected

(Kg) permeability in mD and porosity in % collected by Mr. El Amin Mokthar (Table 1).

Sample

selection

Sample

ID:C17

SampleID:D19

Fluid

preparation

Fluid

preparation

Experiment

1

Experiment

2

Experiment

2


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The four initial selected samples were chosen to have variation in porosity and

permeability values (low porosity and permeability value, mid porosity and permeability

and high porosity and permeability value). After that I narrow my selection to only two

samples due to time constrains. Selected samples range between high porosity and

permeability values to medium porosity and permeability. Sample C17 was chosen for its

high porosity (32.6%) and relatively low permeability (98 mD) so I can detect fluid

behavior with a relative high porous media and low ability of fluid flow. For this sample,

the low permeability value may allow the fluid to interact longer with the host rock.

Sample D19 has relative medium porosity (23.8 %) with low permeability (42 mD). D19

has been selected to examine a mid-properties value compared to previous sample.

4.2 Fluid preparation

Initially three fluids were proposed which are carbonated water, saline water and distilled

water. Due to time constrains and equipment availability I end up using one fluid. Used

fluid in Experiment 1 and 2 was distilled water. Distilled water was expected to be the

most reactive solution compares to other proposed solutions. The distilled was used for

accelerating diagenesis process and alteration to test if fluid changes will lead to porosity

permeability changes.


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4.3 Experiment 1

Experiment 1 is a repetition of the work done by Vega et al. (2011) but using carbonate

sample reservoir rock instead of pure calcite and dolomite minerals. This experiment

conducted to show potential detectable change in porosity and permeability for carbonate

sample as Vega's experiment show potential observable changes in pure calcite and

dolomite minerals porosities. Slight modification was made to the experiment since at

that time we did not have a controllable pump. The experiment set up is shown in figure

(3) Figure shows the experiment set up used in Vegas et al. 2011 experiment.

Figure 3: Experiment 1 setup

PumpInput water

Sample soaked in distilled water

Output water


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Sample analytical techniques were carried before starting the experiment; such as thin

section analysis, SEM/back scattering/ EDS images, 3D CT scan.

To repeat and check the experiment in Vega et al (2011) for a reservoir rock, I used

sample C17 that has highest porosity and permeability. The high porosity and

permeability of sample C17 might help in observing possible changes better than D19.

The used sample was initially dry then it is soaked in an elementary flask that filled with

distilled water. In addition to that distilled water was pumped to the sample and this

induces some movement on the preexisting fluid on the elementary flask. Sample was

subjected to flow for 30 min then we turn off the pump and keep the sample soaking on

the fluid. In consequence, the flow rate in this experiment is not considered as a major

controlling factor since there is no real flow through the samples. This procedure was

repeated for different experiment 1 stages (exposure time) table 2. For example in 2 hour

exposure time: the first 30 min was flowing a fluid through sample , second 30 min

soacking the sample on the fluid without flow then this procedure is repeated for the next

hour. Experiment 1 carried for six stages which are: 1 hour, 2 hours, 3 hours, 4 hours, 5

hours and 6 hours of exposure time.

The flow rate in this experiment was not controlledas mentioned before and it was about

(6 ml/min). The input and output solution were collected in order to capture any potential

changes in element composition (ICP-Ms analysis). Velocity, porosity and permeability

measurements were taken after each experiment stage (exposure time). At the end of

experiment 1, CT scan was carried again to capture possible changes.


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Table 2: Experiment 1 procedure. An example of the carried procedure (1 hour of

exposure time and 2 hour of exposure time). The procedure was repeated in each

experiment stage. So at any exposure time each one hour is divided to 30 min of fluid

flow and 30 min of soaking the sample without flow.

Exposure time Analytical techniques

before carrying the

experiment

Analytical techniques after

each exposure time

Remarks

At the start point Velocity measurements

Porosity and

permeability

measurements

ICP-MS for sample

CT scanner and SEM

for sample

1hrs Velocity measurements

Porosity and permeability

measurementsCollecting fluids for ICP-MS

analysis

30 min with fluid flow

30 min sucking the

sample

2 hrs Velocity measurements

Porosity and permeability

measurements

Collecting fluids for ICP-MS

analysis


30 min sucking the

sample


30 min sucking the

sample


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Experiment 2

In Experiment 2 I used the setup shown in figure 6. This setup adds more accuracy and

control to the experiment; the sample is placed in a core holder which ensures maximum

contact between fluid and sample. For this experiment setup, I decided to saturate the

sample before each flowing stage in order to accelerate the changes if it they occur.

Figure 4: Experimental setup for experiment 2 (courtesy of El Amin Mokhtar, 2012)

Before starting experiment 2, CT scan was carried for sample C17 and D19. The initial

suggested flow rate for reservoir simulation is 1 ft/day. The proposed flow rate in this

experiment was lowered to a minimum rate (1 ft/day which is approximately equal to

0.24 ml/min) to avoid hydraulic fracturing. In this experiment the sample was subjected

to the assigned flow rate directly since the sample is placed in a core holder. The initial

used pressure was 200 psi which is the limit capability of the available lines (plastic

lines). At the start point before placing the sample, I flashed the system with distilled


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water, Methanol and Ethanol to ensure that there is no any oil or salt contaminated in the

lines and to ensure that the only effect on the sample is the distilled water. After placing

saturated sample inside the core holder the distilled water was flowed through the sample.

Fluid flow followed a timing schedule shown in table 3 for sample C17 and table 4 for

sample D19. After each flow time the sample was removed from the system and dried to

take porosity, permeability and velocity at dry condition. The input and output fluid were

collected for ICP analysis of elements composition. The system flashed with distilled

water Methanol and Ethanol again after each stage (injected pore volume). The flowing

schedule in this experiment depended on the filled pore volume. From the initial porosity

measurements we calculated the actual sample pore volume then we multiplies it by the

needed injected pore volume to get the required time for the experiment.

For example at the first stage (5 injected pore volume)

Total number of pore that need to be filled= actual sample pore volume * injected pore

volume

Total number of pore that need to be filled = 15.782 *5= 78.91 ml

Time required to fill the pore= Total number of pore that need to be filled /flow rate

Time required to fill the pore= 78.91 ml / 0.2 (ml/min)

Time required to fill the pore= 394.55 min~

6.5 hours


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Table 3: Experiment 2 stages for sample C17 .

Filled pore volume Sample pore volume Used flow rate Time ( hours)

5 15.782 0.2 6.5

50 15.928 0.2 66

75 15.964 0.2 98

100 16.051 0.2 134

150 16.08 0.2 201

Table 4: Experiment 2 stages for sample D19.

Filled pore volume Sample pore volume Used flow rate Time ( hours)

20 15.55 0.2 26

50 15.641 0.2 65

80 15.696 0.2 105

120 15.914 0.2 159

After carrying experiment 2 for both samples, CT scan was carried to capture any

possible changes.

Chapter 5: Results

5.1Sample C17



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Thin section

C17 is Calcite foraminifers packstone (Figure 5). Calcite composition of the sample

observed clearly as the sample is stained with red lizarin (Figure 6). In the stained part;

most of the grains reflect red to pinkish color which is an indication to calcite. The thin

section of sample C17 is full of micrite (Figure 5). Most of the observed pores in this thin

section are cemented with Calcite. The thin section quality is considered as poor quality,

since the diagenesis sequence cannot observe clearly even at very high magnification.

Figure 5: Sample C17, foraminifers

packstone full of micrite

Figure 6: C17 thin section, where half of

the section is stained with red lizarin. In the

stained part most of the grains reflect

pinkish color which is an indication of

calcite cementation.


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SEM/ backscattering/ EDS

SEM and backscattering images of the sample were captured to get an idea about pore

structure type, grain shape and approximate porosity. The SEM, EDS and backscattering

analysis were applied by cutting small piece of the sample. From the SEM images at very

low resolution ( 500 Mm) (Figure7) macro porosity observed. Increasing the resolution

to (50 Mm) shows more detailed of sample C17 internal structure. At resolution of 50

Mm the observed grains are surrounded to irregular grains with micro porosity (Figure 8)

between the grains. Some of the grains are covered by micritic grain and this is confirms

the abundance of micritic grains that observed in the thin section part of sample C17.

Figure 7: Overview of C17 SEM image at

very low resolution, Macro pores spaces

observed.

Figure 8: Irregular (Calcite??) grains

covered with micritic grains. Yellow circles

indicate the micro pore spaces (less than 30

Mm)


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Backscattering images of the same sample at resolution of (500 Mm) give an indication

of micro and macro porosity supporting the SEM images figure 9.

Figure 5: Backscattered image of sample C17,

where the black dots (background) represent the

pore space and white to very light grey represent

the grains.

The EDS (energy dispersive x-ray spectroscopy) report of sample C17 shows that the

sample is mostly consist of Calcium carbonate figure 10. EDS analysis of sample

composition might would help in understanding the interaction mechanism.


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Figure 10: EDS analysis of sample C17 most of the sample is consist of calcite.

3D CT images

Processed images using Sakher program

5.1.2 Acoustic velocity measurements

Experiment1

Velocity measurements for the sample were taken at each experiment stage/exposure

time at dry conditions. The Vp response of sample C17 was generally increasing with

Element Weight% Atomic%

C K 16.90 26.82

O K 46.99 56.00

Ca K 36.11 17.18

Totals 100.00

Quantitative results

Weight%

0

10

20

30

40

50

C O Ca


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increasing the exposure time if we compare the Vp value at zero time with the Vp value

at the last stage ( after 6 hour of exposure time) figure 11 . However, the measured Vp

values through experiment 1 was fluctuating; decreasing the first stage (after 1 hr of

exposure time) then increase after 2 hour of exposure time. The measured Vp values

decreases again with increasing the exposure time from 2 hour to 4 hour. At the last two

stages the measured Vp was increasing with increasing of exposure time. (Comment on

error)

Figure 11: The measured Vp values at dry condition with the increasing of the exposure

time.The measured Vp Values were changin with increasing the exposure time, but this

changes in Vp value were not follwing a general trend. The Vp values were fluctuating

with increasing the exposure time.

The measured Vs values for the same sample have more clear trend with increasing the

exposure time. The Vs values increases with increasing the exposure time from 0 time to

2 hour of exposure time figure 12. Then the Vs values start to deacrese with increasing

2380.00

2390.00

2400.00

2410.00

2420.00

2430.00

2440.00

2450.00

2460.00

0 1 2 3 4 5 6 7

Vp(m/s)

Time (hours)

Vp ( m/s) Vs exposure time (hrs)


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the exposure time form 2 hour of exposure time to 6 hour of exposure time. Measured Vs

for sample C17 shows a decreasing polynomial trend with increasing the exposure time.

Figure 12: Measured Vs vlaues of sample C17 in experiment 1 versus the exposure time.

Vs values show a decreasing polynomial trend with increasing the exposure time

Experimen 2

Velocity measurements for sample C17 were taken during the second experiment after

each stage (injected pore volume) at dry conditions. Measured Vp increases with

increasing injected pore volume (exposure time) figure 13. Vs for sample C17 shows an

increasing polynomial trend with increasing the exposure time. The increasing of velocity

give an indication that the sample becomes stiffer since the sound wave is traveling faster

with less disturbance. Add bulk modulus

R = 0.8929

1250.00

1300.00

1350.00

1400.00

1450.00

1500.00

0 1 2 3 4 5 6 7

Vs(m/s)

Time (hrs)

Vs (m/s) versus time (hrs)


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Figure 13: Measured Vp for sample C17 through experiment 2 at dry conditions. Vp

readings are increasing with increasing the injected pore volume/ exposure time.

Measured Vs values for sample C17 through the second experiment was fluctuating with

increasing the injected pore volume figure 14. In general there was an increase if we

compare the first value (zero injected pore volume) with the last value (100 injected pore

volumes).

R = 0.9534

2400

2450

2500

2550

2600

2650

27002750

2800

2850

2900

0 20 40 60 80 100 120

Vp(m/s)

Injected pore volume

Vp (m/s) versus pore volume


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Figure 14: Vs measured values for sample C17 through experiment 2 at dry conditions.

There is a general increase in the Vs values with increasing the injected pore volume/

exposure time.

5.1.3 Porosity

Experiment 1

Porosity measurements of sample C17 were taken after each stage (exposure time) at dry

condition using the porosimeter. Porosity value is increasing with increasing the exposure

time figure 15. Increasing of porosity could be an indication of partial dissolution. On the

same experiment the velocity measurements were also increase and this not expected as

the porosity is increasing also.

1250

1300

13501400

1450

1500

0 20 40 60 80 100 120

Vs(m/

s)

injected pore volume

Vs (m/s) versus Pore volume


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Figure 15: Porosity of sample C17 measured after each stage ( exposure time) at dry

condition. The porosity measurements is incresing with increasing the exposure time.

Experiment 2

In the second experiment the porosity measurements were also taken after each stage (

exposure time/ injected pore volume). The main differences between experiment one and

experiment 2 as mentioned in chapter ( 5) are : the sample was intially saturated in the

second experiment and sample was subjected to fluid flow within closed system.

Additional control in the second experiment might help in enhancing the reaction or

changes on the sample. Porosity measurements of sample C17 on the second experiment

were increasing with increasing the injected pore volume/ exposure time figure 16.

R = 0.8815

24.4

24.6

24.8

25

25.225.4

25.6

25.8

0 1 2 3 4 5 6 7

Porosity(%)

Time (hrs)

Porosity (%) versus Time (hrs)


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Figure 16: Porosity measurements of sample C17 in experiment 2 at dry conditions. The

porosity is incresing with increasing the injected pore volume.

5.1.4 Permeability

Experiment 1

The permeability measurements were also taken at dry conditions after each stage

(exposure time). Permeability values are generally decreasing with increasing the

exposure time as shown in figure 17. However, we can observe a fluctuating trend of

permeability values as the exposure time increase. From 2 hour exposure time to 4 hour

exposure time the permeability value is increasing. At the same stages (from 2 hour

exposure time to 4 hour exposure time) the Vp values is decreasing. From 4 hour of

exposure time to 6 hour of exposure time the permeability is decreasing whereas, the Vp

is increasing

25.5

25.6

25.7

25.8

25.926

26.1

26.2

0 20 40 60 80 100 120

Porosity(%)


Porosity (%) versus Pore volume


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Figure 17: Permeability measuremenst of sample C17 during experiment 1 at dry

conditions. The permeability values in general is decreasing with an increaing of

exposure time.

Experiment 2

Permeability values for sample C17 in the second experimenst were also taken after each

stage (injected pore volume/ exposure time). Generally we can said that the permeability

is increasing with increasing the exposure time figure 18. For the same experiment and

same sample the porosity measurements were also increasing with increasing of injected

pore volume/exposure time.

116.5

117

117.5

118

118.5

119

119.5

120120.5

121

0 1 2 3 4 5 6 7

PermeabilityKg(mD)

Time (hrs)

Permeability Kg (mD) versus Pore

volume


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Figure 18: Permeability measurements of sample C17 through experiment 2. The

permeability values generally increaing with increasing of injected pore volume/

exposure time.


ICP-MS was used to examine changes elemental composition of the fluids injected, post-

experiment as well as the solution used to saturate the rock at the beginning of the

experiment. For the second experiment the fluid used to saturate the sample is the same

the injected fluid (reference point/ zero point). The elemental composition analysis of the

fluid through the experiment might help in understanding diagenesis or fluidrock

interaction. The most important tracked elements are the Ca, Mg and Fe, since our

samples are mainly carbonate (calcite C17). In each stage the input and output fluids

were analyzed. The Input fluid (reference) for each stage is represented at the zero time;

for example: for the second stage (after 2 hour of exposure time), the input fluid is

represented at zero time and the output is represented at 2 hour point. Each element

reading is normalized through the experiment stages. For example in the case of Ca

116.000

116.500

117.000

117.500

118.000

118.500119.000

119.500

0 20 40 60 80 100 120

PermeabilityKg(mD

)


Permeability Kg (mD) versus Pore

volume


31/52

element I found the maximum reading of Ca through the experiment stages and divided

the reading at each stage by this maximum number; similar procedure was applied for the

remaining elements.

Experiment 1

The ICP analysis of the input and output fluid shows that Ca element content is generally

increases with increasing the exposure time. For the first two stages (after 1 hour of

exposure time and after 2 hour of exposure time, the Ca content considered to be

increasing compared to the reference point and increasing with respect to each other with

increasing in exposure time. This increasing means that after exposure time of 2 hour we

get more Ca content on the fluid than 1 hour of exposure time. This is might means that

dissolution is increased with increasing the exposure time from 1 hour to two hours. Then

by trying to compare output Ca content from 2 hours of exposure time to 4 hours we can

say that the Ca output is decreasing by comparing output fluid content of these stages, but

it is still increasing if we compare it with the input fluid content. This could mean that by

increasing the exposure time the dissolution rate will decrease. However, the Ca content

start to increase again at the last two stages of the experiment which again might give an

indication to increasing in dissolution rate in the sample by the fluid. The Ca content of

the output fluid for sample C17 in experiment 1 was fluctuating and increasing in

general. However, this trend might not be really representative to the real fluid rock

interaction since the exposure time is very low (maximum exposure time in experiment 1

is 6 hours). Fe and Mg content were almost following the same trend of the Ca content

with increasing of the exposure time. Both Fe and Mg were generally increasing with

increasing the exposure time figure 19.


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Figure 19: Ca, Fe and Mg readings of the input and output fluids injected to sample C17

in experiment 1. Al of them shows a general increasing with increasing the exposure time

compared to the reference value (zero time).

Experiment 2

For the second experiment Ca and Mg content were following similar trend with an

increasing of injected pore volume/ exposure time. Ca and Mg content were generally

increasing with increasing of injected pore volume/ exposure time compared to the

reference point (zero injected pore volume/exposure time). However if we compare the

output content of each stage together we can say that the output content get less as we

increase the injected pore volume/ exposure time. This is mean that by increasing the

injected pore volume/ exposure time the dissolution occurrence in the sample might

decrease. On the other hand the Fe content show a general increasing compared to the

reference value and compared to different stages (injected pore volume) figure 20

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.91

0 1 2 3 4 5 6 7Ele

mentcontent(normalizedvalues)

Time (hrs)

Element content (normalized values) Vs

Time (hrs)

Ca

Mg

Fe


33/52

Figure 20: Ca, Mg and Fe content of the input and output injected fluid to sample C17 in

experiment 2. All of them show a general increasing compared to the reference point

(zero point) with an increasing of the injected pore volume/ exposure time. Ca and Mg

output are considered to be decrease comparing the output fluid content of each stage

together. However, the Fe content is increasing if we compare the output fluid content at

each stage together

5.2 D19

5.2.1 Image analysis

Thin section

D19 is limestone sample with dolomite cementation. The dolomite content is clearly

observed by the dolomite crystal shape figure 21, which is a typical shape of dolomite

crystal (add reference). In the stained part of the sample the grains reflect white color

which is an indication of dolomite content (add reference). Most of the grains are

0

0.2

0.4

0.6

0.8

1

0 20 40 60 80 100 120 140

Elementcontent(normalizedvalues

)

injected pore vloume

Element content (normalized values) Vs.


Ca

Mg

Fe


34/52

recrystallized. Most of the observed pores in this thin section are cemented with calcite or

dolomite. The thin section quality is considered as poor quality, since the diagenesis

sequence cannot observe clearly even at very high magnification.

Figure 21: Sample D19, dolomite crystal with saddle

shape is clearly observerd. This part of thin section is

stained with red lizarin

SEM/ backscattering/ EDS

SEM and backscattering images of the sample were captured to get an idea about pore

structure type, grain shape and approximate porosity. The SEM, EDS and backscattering

analysis were applied by cutting small piece of the sample. At 300 Mm resolution macro

porosity could be observed, represented by dark areas (yellow circles) in the SEM image


35/52

figure 22. At resolution of 30 Mm we can clearly observe the dolomite crystal that has

the same shape of dolomite crystal observed in the thin section figure 23.

The back scattered images of sample D19 confirm the occurrence of macro porosity at

resolution of 500 Mm figure 20, where the black background represent the pore spaces

and the white areas represent the grains figure 24.

Figure 22: D19 SEM image, the yellow

circle represent the macro porosity.

Figure 23: D19 SEM image, the blue circle

represent the dolomite crystal.


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Figure 24: Back scattered image of sample D19 at

resolution of 500 Mm. Black background represent

the pore space whereas the white to grey color

represent the grains.

The EDS report for sample D19 shows that the sample mostly consists of calcite with

dolomite. The dolomite content is indicated by Mg occurrence figure 25.

Element Weight% Atomic%

O K 58.90 74.39

Mg K 15.21 12.64

Ca K 25.25 12.73

Fe K 0.64 0.23

Totals 100.00

Quantitative results

Weight%

0

10

20

30

40

50

60

O Mg Ca Fe


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Figure 25: EDS analysis of sample D19, most of the sample is calcite with dolomite

content.

CT scan

Processed images by Sakhr program.

5.1.2 Acoustic Velocities or (Vp and Vs)

Velocity measurements for sample D19 were taken at each experiment stage (injected

pore volume/exposure time). The velocity was measured at dry condition. Vp is

increasing with increasing injected pore volume/ exposure time figure 26. This indicates

that the sample stiffness might be increase.

R = 0.9202

2950

3000

3050

3100

3150

3200

3250

3300

0 20 40 60 80 100 120 140

Vp(m/s)


Vp (m/s) versus Injected pore volume


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Figure 26: Measured Vp for sample D19 in experiment 2. Vp measured at dry condition.

The Vp increases with increasing the injected pore volume/ exposure time.

Measured Vs values generally are increasing with increasing of the injected pore volume

/exposure time. However, the values were not showing clear increasing trend with

increasing the injected pore volume/ exposure time as the values fluctuating through the

experiment figure 27.

Figure 27: Measured Vs values of sample D19 on dry conditions. Generally the Vs is

increasing with increasing the injected pore volume/ exposure time.

1750

1800

1850

1900

1950

2000

2050

2100

2150

0 20 40 60 80 100 120 140

Vs(m/s)


Vs (m/s) versus injected pore volume


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5.2.3 Porosity

Porosity measurements of the sample were taken at dry condition after each stage (after

each injected pore volume/ exposure time). Porosity measurements of the sample are

increasing with increasing the injected pore volume figure 28. The increases of porosity

might be an indication of dissolution on the sample which leads to increase in pore spaces

Figure 28: Porosity measurements of sample D19 on experiment 2. The measurements

were taken on dry conditions. Porosity values are increasing with increasing the injected

pore volume/ exposure time.

5.2.4 Permeability

The permeability measurements were also taken on dry condition and after each stage

(after each injected pore volume/ exposure time). Generally the permeability value is

increasing compared to the initial value at zero point. Increasing on permeability value is

very sharp and clear at the first stage (after injecting 20 pore volumes) after that the

permeability values are slightly fluctuating figure 29.

23.2

23.3

23.4

23.5

23.6

23.7

23.823.9

24

24.1

0 20 40 60 80 100 120 140

Porosity(%)


Porosity (%) versus Injected pore

volume


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Figure 29: Permeability measurements of sample D19 on experiment 2. The readings

were taken on dry condition. Generally the permeability is increasing. The permeability

show sharp increasing after the first stage (after 20 injected pore volumes). Then the

permeability reading is slightly fluctuating.

50

52

54

56

58

60

62

0 20 40 60 80 100 120 140

PermeabilityKg(mD)

Pore Volume

Permeability Kg (mD) versus Pore volume


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ICP-MS was carried to examine changes elemental composition of the fluids injected,

post- experiment as well as the solution used to saturate the sample. For the second

experiment the fluid used to saturate the sample is the same the injected fluid (reference

point/ zero point). Tracking possible the elemental composition changes might help in

understanding diagenesis or fluidrock interaction. The most important tracked elements

are the Ca, Mg and Fe, since our samples are mainly carbonate (calcite + Dolomite

D19). The input and output fluid were collected at each stage of the experiment. The

input fluid in each stage is the same fluid and it represented in figure 30 as the zero point.

Each element reading is normalized through the experiment stages as mentioned in the

ICP analysis for sample C17.

Experiment 2

Both elements Ca and Mg are having the same trend. Ca and Mg content on the output

samples considered to be increasing if we compare them to the initial value (zero value).

Ca and Mg reach its maximum content on the output fluid in the second stage (after 20

injected pore volumes). Then the output content of Ca and Mg is decreased compared to

the second stage values. As we increase the injected pore volumes/ exposure time, the

output content of Ca and Mg element is decreases figure 30. Thats mean we are

dissolving less Ca and Mg elements from the sample (D19). Most of the Ca and Mg

elements have been washed from the sample at the first stage (after 20 injected pore

volume). The Fe content is increasing compared to the initial value ( zero point). As we

increase the injected pore volume/ exposure time, the amount of dissolved Fe from the

sample/ output content is increase.


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Figure 30: Ca, Mg and Fe content on the input (zero point) and output injected fluids. Ca and Mg

have the same trend. Both are increasing compared to the intial point (zero point). However, Ca

and Mg content are decreasing through the experiment. Fe content of the output fluid is

increasing through the experiment.

Chapter 6: Analysis

6.1 Sample C17

The used techniques here which are thin section analysis, SEM images and EDS analysis

show that sample C17 is mainly a calcitic limestone. Pore distribution for sample C17

from the thin section indicated an abundance of microporosity. Additionally the SEM

images show the occurance of both micro porosity (below 30 Mm ) and macro porosity at

(500 Mm ) as mentioned in chapter 5. However, the thin sections (approximately less

than 1 cm~0.5 cm) and sample pieces (up to 2 mm in diameter) used for SEM images

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 20 40 60 80 100 120 140Elementcontent(Normalizedvalues)

Injected pore volume of the sample

Element content (normalized values) Vs

injected pore volume of the sample

Ca

Mg

Fe


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may not be representative of the whole core plug and some features in the pore space

distribution and pore structure might be missing.

3D CT scans of sample C17 taken at three stages: (1) before any treatment, (2) after the

first experiment, and (3) after the second experiment were expected to help in detecting

any changes in the sample through whole process. The 3D CT scan scanned the whole

sample. Produced videos from these three stages were slightly helpful in tracking the

changes qualitatively. As mention in the results part between the three stages the main

changes were in the micoporosity. General decreasing in the microporosity was observed.

Studying the produced images of the three stages using Sahker (image processing and

analysis program) , I found that the microporosity were below the image resolution ( 40

Mm ) and, consequently, not detected. Comparing the porosity estimated from the

program with the actual value at the end of each stage confirmed that there is a gap /

missing data that the program was not able to read from the images due to the images

quality. Estimated value from each stage was less than actual measured value by the

porosimeter as shown in table 1.

Table 1: Porosity values of sample 422-17 before any treatment, after the first experiment

and after the second experiment estimated form Sakher program and measured by the

porosimeter.

Stage

number

Experiment

Stage

Estimated

porosity

value

form

Actual

porosity

measured by

porosimeter

Porosity difference

Total Porosity

Estimated Porosity

(%)


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Sakher

(%)

(%)

1 Before any

treatment

9.5 24.4 14.9

2 After first

experiment

11.1 25.6 14.5

3 After

second

experiment

10.9 26.1 15.2

The histogram and the maximum density probability of the grains (solid phase) in each

stage shows that from stage 1 to stage 2 we have a general increasing in grains density

probability whereas from stage 2 to stage 3 we have a general decreasing in grains

density probability value. For example by taking 400 slices from the sample in each stage

(starting from slice 1 to slice 400) the changes were as shown in table 2.

Table 1: Grain probability distribution value of sample 422-17 before any treatment, after

the first experiment and after the second experiment.


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Comparison between porosities at stage 1 and stage 2 cannot be made since the sample

lost a small volume after the first experiment which might affect the probability

distribution readings and total porosity. Moving from stage 2 to stage 3 we can observe a

decreasing in the grain maximum density probability.

Moving from stage 2 to stage 3, there is also a loss in the sample volume after stage 3

(approximately 0.4 g) but it is very small compared to sample loss after stage 2 previous

loss (approximately 4g). As the loss in C17 sample volume after stage is negligible, I

assumed that there is no loss in the sample volume. The decreasing of the grain maximum

density probability (from stage 2 to stage 3) with this assumption might indicate an

occurrence of dissolution process.

Comparing velocity and porosity results of the sample C17 in the second experiment, we

can see that their behavior is against the expected trends. More reasonable expected trend

is to have opposite response from porosity and velocity compared to each other; e.g.: if

the porosity is increasing we will be more likely expecting to have a decreasing in

velocity value. Increasing in porosity means that we have more open spaces that could be

filled with water, air, gas or oil. The seismic wave traveling through the solid matter is

Experiment Stage Grain maximum density

probability

1.Before any treatment 0.045

2.After first experiment 0.056

3.After second experiment 0.043


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expected to be faster than traveling through gas or liquid mater. Increasing the porosity

means that we are introducing a disturbance to the traveling wave and this would lead to

decreasing in wave velocity. However, the velocity (Vp and Vs) were increasing with

increasing exposure time /injected pore volume and this could be an indication to

precipitation occurrence. As the velocity is increasing, the rock sample expected to be

stiffer. Two reasonable ways in increasing the stiffness of the sample might be: first

rearranging pore distribution and grains in a way that would add to rock stiffness , second

the occurrence of precipitation process that might help in filling the pore spaces.

As discussed in the chapter 5, ICP analysis of the fluids (input and output) for experiment

1 and experiment 2 shows an increase of Ca, Mg and Fe content on the output fluids

compared to the input content (zero point).

For Experiment 1 the Ca, Mg and Fe content of the output were increasing as the

exposure time is increased from 0 to 2 hours of exposure time. The increases on the

elements (Ca, Mg and Fe) content of the output fluid could indicate dissolution from the

sample at the very first stages of the experiment. Then from 2 hours of exposure time to 4

hours the content is decreases which mean that we dissolve less of these elements from

the sample, or we could have partial precipitation. From 4 hours of exposure tome to 6

hours of exposure time which again indicate occurrence of dissolution.

As mentioned in the chapter 5, Ca and Mg content of the output fluids have similar trend

in experiment 2. Ca and Mg content were generally increasing compared to the reference

point (zero injected pore volume/exposure time). As the injected pore volume is

increased/ exposure time the output fluid Ca and Mg content is decreases. The decreasing


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of Ca and Mg content indicates that we have a dissolution process, but as we increase the

injected pore volume/ exposure time the dissolving mechanism is reduced. The reduction

of dissolving mechanism could indicate partial occurrence of precipitation.

Potential precipitation of ion in the sample can be supported by the increasing on Vp as

mentioned before and general decreasing of Ca and Mg content on output fluid for

Experiment 2.

Decreasing of grain maximum density probability from stage 2 (after experiment 1) to

stage 3 (after experiment 2) might mean an increasing in pore space/ total porosity and

this analysis can be supported by the general increasing on actual measured porosity

(from the porosimeter) in both experiments.

Generally, we can say that there are observable changes in both experiments for sample

C17. The changes indicated the occurrence of both mechanisms (dissolution and

precipitation). The dissolution might have the higher influence on the rock fluid

interaction as it is also shown in total porosity measurements of the sample through both

experiment 1 and 2. However, the changes are clearer on experiment 2 as we had higher

exposure time/ injected pore volume.

6.2 Sample D19

Thin section analysis, EDS and back scattering images of sample D19 before any

treatments confirmed dolomite content on the sample as mentioned in chapter 5

Porosity and velocity changes for sample D19 showed a similar trend as sample C17 on

experiment 2. Total porosity and Vp values increased through experiment 2. General

increasing on total porosity might indicate a dissolution process whereas the increasing of


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The ICP analysis of the fluid shows that after running the experiment 2 for both samples

and for 20 injected pore volumes, the Ca and Mg content reach the maximum amount.

The output Ca and Mg content from sample D19 (approximately 10099.71 ppm after 20

injected pore volumes) is much higher than on sample C17 (approximately 1997.6 ppm

after 20 injected pore volumes). This might also indicate that the low permeability value

of sample D19 helped in trapping the fluid and increasing the possibility of rock fluid

interaction/ dissolution. Another thing that should be considered is that both samples

were saturated with input fluid before running the experiment. Then after running the

experiment for 20 injected pore volume we got those results. The saturation of the sample

before injecting any fluids might help in weakening the grains especially in the pore

spaces where the fluid might get higher contact with the sample material. This might help

in understanding why we get clearer results in experiment 2 for both samples than

experiment 1 for C17.

The permeability changes in both samples are not very clear. Permeability values are

fluctuating but generally increasing for sample C17 and decreasing for sample D19 figure

31. However in the last two steps the changes on permeability values are very low and

this might suggest that carrying the experiment for longer exposure time might lead to

constant permeability value or might introduce other changes as we increase the exposure

time.


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Figure 31: permeability values of sample C17 and D19 in experiment 2. Both show

general increasing.

Porosity for both samples in experiment 2 was increasing with increasing the injected

pore volume/ exposure time figure 32.

0.000

20.000

40.000

60.000

80.000

100.000120.000

140.000

0 50 100 150

PermeabilityKg(mD

)


Permeability of sample C17 and D19

Vs injected pore volume

C17-EX2

D19-EX2

23

23.5

24

24.5

25

25.5

26

26.5

0 50 100 150

porosity(%)


Porosity (C17 and D19) Vs injectedpore volume

C17-EX2

D19-Ex2


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Figure 32: Porosity measurements of sample C17 and D19 through experiment 2. Both

porosity reading are increasing with increasing the injected pore volume/ exposure time.

6.4 Comparison with previous studies

Comparing the results of my experiment with Vegas 2011 results, the measured acoustic

velocity of the sample (pure calcite) in dry condition is generally decreasing with

increasing exposure time figure 33.

Figure 33. Calcite (i) dry and (ii) saturated sample velocity change with different

experimental order. Vega et.al(2011).

In experiment 1 sample C17 velocity measurements were increases with increasing

exposure time. Experiment 1 conditions were similar to the applied experiment in Vegas

et. al(2011) research. The main difference is that tin Vegas 2011 experiment the used

sample is pure calcite whereas, in my research I used carbonate sample from real

reservoir. Heterogeneity of the sample used in my research my add complexity in fluid

rock interaction mechanisms, understanding sample behavior and in tracing the

petrophysical properties changes by acoustic velocity. Measured porosity form Vegas


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research was not has a clear decreasing trend. On the other hand for the sample used in

my research the porosity was increasing with increasing the exposure time.

6.5 Implication

Chapter 7: Conclusion

Chapter 8: Recommendation and further work

master thesis miaad

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