This research evaluated the impact of matrix acidizing treatment on acoustic characteristics, which studies show are lacking or have never been investigated previously. Furthermore, in the assessment of geomechanical rock properties and elastic and petrophysical parameters before and after acid injection, one of the new concepts discovered during the lab experiment observation of the acoustic waveform before and after acid treatment for the tested rock sample is that the initial arrival time before acid treatment is 21.6 microseconds, with a delay of 31.2 microseconds attributed to the wormhole channel and mineral disintegration. CT-Scan applications in matrix acidizing were investigated in this research; additionally, a 3D view of plug samples was constructed to represent the wormhole extension via CT-processing software.

1. i
Republic of Iraq
Ministry of Higher Education
and Scientific Research
University of Baghdad
College of Engineering
Department of Petroleum Engineering
EXPERIMENTAL STUDY AND ANALYSIS OF MATRIX
ACIDIZING FOR MISHRIF FORMATION-AHDEB OIL FIELD
A Dissertation
By
USAMA SAHIB SALIH
(MSc 2004)
Submitted to the College of Engineering-Department of Petroleum
Engineering
University of Baghdad
In partial fulfillment of
The requirements for the degree of
DOCTORATE OF PHILOSOPHY IN PETROLEUM ENGINEERING
Supervised by: Prof. Dr. Ayad Abdulhaleem
July 2022

2. ‫ميحرلا نمحرلا هللا مسب‬
"
ً‫ة‬
َ‫ف‬‫ِي‬‫ل‬
َ‫ج‬
ِ‫ض‬ْ‫ر‬َ‫أ‬ْ‫ل‬‫إ‬‫ي‬ِ‫ف‬ ٌ‫ل‬ ِ
‫ع‬‫ا‬ َ‫ج‬‫ي‬
ِّ‫ن‬ِ‫إ‬ ِ
‫ة‬
َ‫ك‬ ِ‫ئ‬‫ا‬َ‫ل‬َ‫م‬
ْ‫ل‬ ِ‫ل‬ َ
‫ك‬
ُّ
‫ب‬َ‫ر‬ َ‫ال‬َ‫ق‬ ْ‫ذ‬ِ‫إ‬َ‫و‬
ۖ
ُ‫ل‬ َ
‫ع‬ْ‫ج‬
َ‫ت‬َ
‫إ‬‫وإ‬
ُ‫ل‬‫ا‬َ‫ق‬
ُ
‫س‬ِّ‫د‬
َ‫ف‬
ُ‫ي‬َ‫و‬ َ‫ك‬ِ‫د‬ْ‫م‬
َ‫ح‬ ِ
‫ت‬ ُ‫ح‬
ِّ‫ي‬ َ
‫س‬
ُ‫ي‬ ُ‫ن‬
ْ‫ح‬
َ‫ت‬َ‫و‬ َ‫اء‬ َ
‫م‬ ِّ‫د‬‫ل‬‫ا‬ ُ‫ك‬ ِ
‫ف‬ ْ‫س‬
َ‫ي‬َ‫و‬‫ا‬ َ‫ه‬‫ي‬ِ‫ف‬ ُ‫د‬ ِ
‫س‬
ْ‫ف‬ُ‫ي‬‫ن‬ َ‫م‬‫ا‬ َ‫ه‬‫ي‬ِ‫ف‬
َ
‫ك‬
َ
‫ل‬
ۖ
َّ‫م‬
ُ‫ث‬‫ا‬ َ‫ه‬َّ‫ل‬
ُ‫ك‬ َ‫اء‬َ‫م‬ ْ
‫س‬َ‫أ‬ْ‫ل‬‫إ‬ َ‫م‬َ‫ذ‬‫إ‬ َ‫م‬
َّ‫ل‬ َ
‫ع‬َ‫و‬* َ‫ون‬ُ‫م‬
َ‫ل‬ ْ
‫ع‬َ‫ي‬
‫أ‬َ‫ل‬‫ا‬ َ
‫م‬ ُ‫م‬
َ‫ل‬ ْ
‫َع‬
‫إ‬‫ي‬
ِّ‫ن‬ِ‫إ‬ َ‫ال‬َ‫ق‬
‫ي‬ِ‫ن‬‫و‬
ُ‫ي‬ ِ‫ب‬‫ن‬َ
‫إ‬ َ‫ال‬ َ‫ف‬َ‫ف‬ ِ
‫ة‬
َ‫ك‬ ِ‫ئ‬‫ا‬َ‫ل‬َ‫م‬ْ‫ل‬‫ا‬‫ي‬
َ‫ل‬ َ
‫ع‬ ْ‫م‬
ُ‫ه‬
َ
‫ض‬َ
‫ر‬
َ‫ع‬
* َ‫ن‬‫ي‬ِ‫ف‬ِ‫اذ‬ َ
‫ص‬ ْ‫م‬
ُ‫ت‬‫ن‬
ُ‫ك‬‫ن‬ِ‫إ‬ ِ‫أء‬َ‫ل‬ُ‫و‬
ََٰ‫ه‬ ِ‫اء‬َ‫م‬ ْ
‫س‬َ
‫ا‬ ِ‫ئ‬
‫ا‬ َ‫ن‬َ‫ن‬ْ‫م‬
َّ‫ل‬ َ
‫ع‬
‫ا‬ َ
‫م‬‫أ‬َّ‫ل‬ِ‫إ‬‫ا‬ َ‫ن‬َ‫ل‬ َ‫م‬
ْ‫ل‬ ِ
‫ع‬
‫أ‬َ‫ل‬ َ
‫ك‬َ‫ب‬‫ا‬َ‫ح‬ْ‫ي‬ ُ
‫س‬‫وإ‬
ُ‫ل‬‫ا‬َ‫ق‬
ۖ
ُ‫م‬‫ت‬ِ‫ل‬ َ
‫ع‬
ْ
‫ل‬‫ا‬ َ
‫ت‬‫ن‬َ
‫إ‬ َ
‫ك‬َّ‫ب‬ِ‫إ‬
‫م‬‫ت‬ ِ‫ك‬
َ
‫ج‬
ْ‫ل‬‫ا‬
”
‫ي‬‫ظ‬‫ع‬‫ل‬‫ا‬
‫ي‬‫ل‬‫ع‬‫ل‬‫ا‬‫لله‬‫إ‬‫دق‬‫ص‬
‫رة‬‫ق‬‫ي‬‫ل‬‫ا‬‫ورة‬‫س‬
30
/
33

3. Supervisor Certification
I certify that the preparation of this dissertation entitled “Experimental
Study and Analysis of Matrix Acidizing for Mishrif Formation-Ahdeb Oil
Field” is being submitted by “Usama Sahib Salih.” It has been carried out
completely under my supervision at the University of Baghdad, College of
Engineering, in partial fulfillment of the requirements for the degree of
Doctorate of Philosophy in Petroleum Engineering.
Signature:
Name Prof. Dr. Ayad A. Al-Haleem
Date: / /2022
In view of the available recommendations, I forward this dissertation for debate by
the examining committee.

4. We certify that we have read this dissertation entitled “Experimental Study and
Analysis of Matrix Acidizing for Mishrif Formation-Ahdeb Oil Field” and as
examining committee, examined the student “Usama Sahib Salih” in its contents
and that in opinion it meets the standard of dissertation for the degree of Doctorate
of Philosophy in Petroleum Engineering.
Signature: Signature:
Name: Dr Falih Hassan Mohammed Name: Dr. Ahmed Askar Najaf
Title: Professor Title: Professor
(Chairman) (Member)
Signature: Signature:
Name:Dr. Abdulkareem Abbas Khalil Name: Dr. Hayder A.Rasheid
Title: Assistant Professor Title: Assistant Professor
(Member) (Member)
Signature: Signature:
Name: Dr. Hassan A. Abdul-Hussein Name: Dr. Ayad A. Al-Haleem
Title: Assistant Professor Title: Professor
(Member) (Supervisor)
Approved by the College of Engineering, University of Baghdad.
Signature:
Name: Dr. Saba Jabbar Neamah
Title: Professor
Acting Dean of the Engineering College
Date: / / 2022

5. DEDICATION
My prject is fully devoted to the omniscient Allah, my respectable
parents, loving wife, my wonderful kids, Brothers and Sisters without
whose continual support this dissertation was not feasible. They are
always a source of inspiration for me.

6. ACKNOWLEDGEMENTS
The Prophet Mohammed (̚‫م‬‫وسل‬ ‫وآله‬ ‫عليه‬ ‫هللا‬ ‫صل‬) said: He who does not thank the
people is not thankful to Allah.
Prof. Dr. Ayad A. Al-Haleem, my supervisor, has provided me with consistent
direction, care, patience, and support over the last several years, for which I am
indebted and grateful beyond measure.
I value the outstanding courses taught by Prof. Dr. Mohammed S. Al-Jawad,
Prof. Dr. Falih Al-Mahdawi, Prof. Dr. Ahmed Askar, Asst. Prof. Dr. Sameera
Hamdallah, and Asst. Prof. Dr. Hassan Al-Taei, among others. Their classes
gave me crucial and basic topics and opened the door for me.
I would also want to thank Dr. Ahmed Al-Yaseri, Dr. Ahmed Al-Khafaji, Dr.
Najah and Dr. Fadhil Al-Shershahi for their constructive criticism and helpful
suggestions throughout this project. Appreciate your daily assistance in the lab,
which influenced the experimental outcomes of this study.
Thank and acknowledge my colleagues Akram Hamoodi, Ahmed Radhi, Raed
Alway, Ahmed Kareem, and Mustafa Rahseid for their insightful support.
I want to thank the personnel of the Reservoir and Geology Department of Ahdeb,
especially Mr. Ibrahem Alsaadi, for his assistance in supplying the necessary
data for this project. You were quite kind to me. I would also appreciate my heroes
Mr. Saif as well as the IDC staff Anwar and Ammar for great efforts to make this
project to be accomplished. My appreciation goes to Eng. Ali Kareem &
Hammody (Wellsite engineer-ANTON Co.) for supplying the required materials
for lab works.
Special thanks and admiration are extended to Mr. Ali Saadi, Mr. Firas (head of
the Geology Department), and Mr. Ali Shareef, the personnel of Midland Oil
Company, for their assistance. For their great contribution. Without your
assistance, I could not have completed this task.
Thanks, are also given to Schlumberger team Dr. Ahmed Al Saedi (Well
Engineer), Ahmed Ismaail (SIS country manager), and Marwa Al-Delfi (Digital
Account Manager). Appreciation also goes to Gilberto Villela (Fracpro Solutions
Engineer) and KAPPA Engineering team whose assistance made this research
feasible. Trust is one of the most crucial factors motivating me to complete my
dissertation.

7. i
ABSTRACT
Carbonate matrix stimulation technology has progressed tremendously in the last
decade through creative laboratory research and novel fluid advancements. Still,
existing methods for optimizing the stimulation of wells in vast carbonate reservoirs
are inadequate. Consequently, oil and gas wells are stimulated routinely to expand
production and maximize recovery. Matrix acidizing is extensively used because of
its low cost and ability to restore the original productivity of damaged wells and
provide additional production capacity. The Ahdeb oil field lacks studies in matrix
acidizing; therefore, this work provided new information on limestone acidizing in
the Mishrif reservoir. Moreover, several reports have been issued on the difficulties
encountered during the stimulation operation of the Ahdeb oil field, particularly for
the development of the Mishrif reservoir. Since the new core flooding system is built
to operate safely and straightforwardly. This study introduced the results of Matrix
acidizing experiments, covering the most recent developments in linear core
flooding. High-permeability flow pathways are created, and a longer and wider
wormhole was generated at a high acid injection rate (6.67 cc/min). The acid
efficiency curve yielded the lowest pore volume injected at the breakthrough of the
𝑃𝑉bt−opt is 2.73 and the 𝑣𝑖−opt=0.6 cm/min; thus, the optimum injection rate that
results in an optimal possible wormhole and the least quantity of acid being used for
this reservoir is 2.16 cc/min.
This research evaluated the impact of matrix acidizing treatment on acoustic
characteristics, which studies show are lacking or have never been investigated
previously. Furthermore, in the assessment of geomechanical rock properties and
elastic and petrophysical parameters before and after acid injection, one of the new
concepts discovered during the lab experiment observation of the acoustic waveform
before and after acid treatment for the tested rock sample is that the initial arrival
time before acid treatment is 21.6 microseconds, with a delay of 31.2 microseconds
attributed to the wormhole channel and mineral disintegration. CT-Scan applications
in matrix acidizing were investigated in this research; additionally, a 3D view of
plug samples was constructed to represent the wormhole extension via CT-
processing software.
A license of Stimpro Stimulation Software has been used to validate the
experimental work to the field scale, making it the most comprehensive instrument

8. ii
for planning and monitoring matrix acid treatment and utilizing actual data to
provide a far better knowledge of the well's reaction, with methods that represent the
reality of what is happening in the reservoir before, during, and after matrix acid
treatments, through the post-treatment skin factor which is the most often utilized
statistic for analyzing stimulation treatments and relies on the geometry of the
wormholed zone. The acid treatment evaluated for the well AD-12, primarily for the
zone Mi4; matrix acid treatments can have their production behavior predicted or
matched using the reservoir simulation and production analysis option, employing
the numerical simulation license software Petrel (Schlumberger) and Rubis
(KAPPA) to determine the efficacy of previous treatments and the economics
associated with future treatments. The estimated oil gain volume and percentage for
the Mi4 unit in Ad-12 using particularly skin value -3.97 computed from Stimpro
software for real stimulation acid job, it is yield enhancement in production of oil
gain volume 6154 barrels as well as 105% increase of gain percentage for three
months after matrix acidizing.

9. iii
TABLE OF CONTENTS
ABSTRACT............................................................................................................ iii
DEDICATION ..........................................................................................................v
ACKNOWLEDGMENTS........................................................................................vi
TABLE OF CONTENTS.........................................................................................vii
LIST OF FIGURES..................................................................................................ix
LIST OF TABLES ...................................................................................................xi
Chapter 1 (Introduction).........................................................................................1
1.1 Preface ............................................................................................................1
1.2 Research Motivation .......................................................................................2
1.3 The Aim and significance of the study.............................................................3
1.4 Fieldwork and data collection..........................................................................5
1.5 Geological Setting …………...........................................................................5
1.5.1 Formation Summary..............................................................................8
1.5.2 Main Lithologic Characteristics............................................................8
1.5.3 Formation Tops.....................................................................................9
1.5.3.1 Formation Pressure Prediction ...............................................12
1.5.3.2 Characteristics of Fluids.........................................................13
Chapter 2 (Literature review)...............................................................................14
2.1 Early Studies of Acid treatment for Mishrif Formation ..............................15
2.2 Acid–Mineral Reaction Stoichiometry ........................................................15
2.3 Models for the Optimum Matrix Acidizing Determination ..........................16
2.4 Growth and Formation of Wormhole shown by CT-Scan …………….......20
2.5 Impact of Acid on Mechanical Properties of Rocks ..................................22
2.6 Design of Carbonate Matrix Acidizing.........................................................23
Chapter 3 (Theoretical Background and Research Methodology) ……………..26
3.1 Preface..........................................................................................................26
3.2 Stimulation type selection............................................................................28
3.2.1 Acid Type compatibility to the treatments........................................29
3.3 Design of the Stimulation Treatment Sequence...........................................34
3.3.1 Preflush..............................................................................................34
3.3.2 Main (Acid) treatment.......................................................................34
3.3.3 Postflush (overflush) ........................................................................35
3.4 HCl acid carbonate reactions.......................................................................35
3.5 Optimal Injection Rate.................................................................................39
3.6 Wormhole Propagation Global Models.......................................................41

10. iv
3.6.1 The Volumetric Model……………………………………………..44
3.6.2 The Buijse-Glasbergen Model...........................................................44
3.6.3 The Furui et al. Model ......................................................................45
3.6.4 Schwalbert Model………………………………………..…………47
3.6.5 Wormholed Region (Radial/Cylindrical) .........................................48
3.6.6 Divergence and heterogeneous rock types………………….……...49
3.6.7 Propagation of Wormhole in Anisotropic Rocks………………...…50
3.7 Well Performance After Treatment…………………………………..……51
3.7.1 Monitoring the performance of acidizing treatment………….…….51
3.7.2 Max. Δp, Max.-Rate-Procedure by Paccaloni……………………...52
3.7.3 Failure of acidifying treatment and the most common reasons …....54
3.8 Impact of Acid Treatment on Acoustic Properties……………………..….55
3.8.1 Determination of Rock Geomechanical Properties……………...…55
3.8.1.1 Young’s Modulus …..…………………………………….56
3.8.1.2 Poisson's ratio …..………………………………………...56
3.8.1.3 Material Index ….…………………………………………57
3.8.1.4 Coefficient of Lateral Earth Pressure at Rest ……………57
3.9 Stimpro Stimulation Software……………………………………………..58
3.9.1 Acidizing Design Mode……………………………………………59
3.9.2 Acidizing Analysis Mode………………………………………….59
3.9.3 Production Analysis Mode………………………………………...59
Chapter 4 (Experimental Work)..…………………………………………….…60
4.1 Introduction……………………………..………………………………….60
4.2 Preparation And Description of Core’s Equipment……………………..….61
4.2.1 Core drilling and cutting……………………………………….…….61
4.2.2 Core Cleaning by Soxhlet Extractor…………………………………63
4.2.3 Core Drying by Oven and Desiccator……………………….……….64
4.2.4 Core Weighting and Dimension ………………….………………….66
4.3 System of Matrix Acidizing (Design and Setup)……………….………….68
4.3.1 System prerequisites…………………………………………...….....70
4.3.2 Components of the system………………………….………………..70
4.3.2.1 Pumps……………………………………………………….70
4.3.2.2 Core-holder………………………………………………….73
4.3.2.3 Accumulators…………………………………….………….73
4.3.2.4 Temperature controllers and heaters…………………….…..74
4.3.2.5 Acquisition of data……………………………………….….75
4.3.3 Methodology for acidizing the matrix in considerable detail……….78
4.3.4 Precautions for Health, Safety, and the Environment…………….....80

11. v
4.4 Ultrasonic Device………………………………………………………….81
4.4.1 Measuring unit………………………………………………………82
4.4.2 Carrying out measurements………………………………………….83
4.4.2.1 Zero-adjustment …………………………………………….83
4.4.2.2 Measuring the Tp of the core samples………………………..84
4.4.2.3 Measuring the Ts of the core samples………………………..85
4.5 Image Processing of Computer Tomography (CT) Scan…………………..86
Chapter 5 (Results and Discussions).……………………………………………..88
5.1 Core measurement analysis ………………..…………………………..….88
5.2 Mineral composition and description…………………………………..….89
5.3 Acid Core Flood Experiments ………………………………………….....95
5.3.1 Basic Properties of Gelled Acid……………………………………..95
5.3.2 Analysis of the Volumetric Dissolving Power (𝝌)……………….....96
5.3.3 How to Get the Optimum Acid Injection Rate……………………...98
5.3.4 Ascertaining the appropriate injection rate………………………...103
5.3.5 Upscaled Global Model for Wormhole Propagation………………107
5.3.6 Monitoring how well the acidizing treatment performance………..110
5.4 Computed Tomography (CT) ……………………………………………111
5.5 Effect of Acid Treatment on The Geomechanical Properties of Rocks….114
5.5.1 Ultrasonic Velocity Sensitivity to Acidized Rock…...…………….114
5.5.2 The Effect of Porosity and Wormhole on the Elastic Characteristics of
Rock………………………………………………………………..117
5.5.3 Impact of Acid Treatment on Acoustic Wave Properties………….119
5.5.4 Effect of Acid Treatment on Rock Mechanical Properties………...123
5.6 Validation of the experimental work to the field scale…………………..128
5.6.1 Pressure Matching …………………………………………………134
5.7 Reservoir Simulation and Production Analysis..…………………………139
5.7.1 Skin impact on production gain……………………………………144
Chapter 6 (Conclusions and Recommendations).……………………….……….153
REFERENCES…………………………………………………………………..158
APPENDIX……………………………………………………………………...169

12. vi
LIST OF FIGURES
Figure 1.1: Global oil demand between 2018 and 2024…………………………... 1
Figure 1.2: Mishrif carbonate series stratigraphic structure………………..………..3
Figure 1.3: AHDEB Field Location Map…………………………………………...6
Figure 1.4: AD-012 Well Location Map……………………………………………7
Figure 1.5: Stratigraphic Column of Ahdeb Field…………………………………10
Figure 1.6: Pressure profiles of AHDEB…………………………………………..12
Figure 2.1: Work flow chart of selection the optimal acid to overcome the most
prevalent carbonate matrix acidizing difficulties…………….....….….21
Figure 2.2: Three core samples of high-resolution CT scans………………………24
Figure 2.3: Simulation of wormhole flow characteristics numerical methods..…. 25
Figure 3.1: Comparison between fracture acidizing and matrix acidizing………..27
Figure 3.2: Acid Injection through a Perforated Completion Wormholes…………28
Figure 3.3: Candidate selection and Stimulation Methods………………………...29
Figure 3.4: Work flow chart of selection the optimal acid to overcome the most
prevalent carbonate matrix acidizing difficulties. …………………....37
Figure 3.5: In a Large-Scale Block Experiment, Wormholes were Generated…….42
Figure 3.6: At the top is CT-scan for injection rates required to created wormhole..38
Figure 3.7: Morphologies of wormhole at various rates of injection…………….39
Figure 3.10: Treatment of the matrix stimulation design chart…………………….53
Figure 3.11: StimPro's Capabilities………………………………………………..58
Figure 4.1: Schematic diagram of the workflow for the experimental procedure…60
Figure 4.2: Photography of rock core acquired from Mi4 in well AD-12…………61
Figure 4.3: FOBCO core driller press……………………………………………..62
Figure 4.4: Plug shaped from both edges with a cutter machine…………………..62
Figure 4.6: Core cleaning by Soxhlet extractor……………………………………64
Figure 4.7: Drying the plugs up to 100 °C in a humidity-controlled oven .………64
Figure 4.8: Desiccator vessel used to keep plugs from the humidity………………65
Figure 4.9: Digital Balance to measure the weight of plugs……………………….66
Figure 4.10: Vernier caliper for measuring plug sample dimension………………66
Figure 4.11: Core sample saturation system……………………………………….68
Figure 4.12: Laboratory configuration system for matrix acidizing………………69
Figure 4.13: Teledyne LC-5000 Precision syringe pump………………………….71
Figure 4.14: ENERPAC type hydraulic pump…………………………………….72

13. vii
Figure 4.15: New modified core holder 10 cm diameter by 18 cm long…………..73
Figure 4.16: Piston accumulator…………………………………………………...74
Figure 4.17: Fiberglass rope heater………………………………………………..75
Figure 4.18: Electrical Output Signals Circuit for the pressure sensor……………76
Figure 4.19: KELLER pressure transducers connected to the flow line system…..76
Figure 4.20: Universal Data Logger UDL-100…………………………………….77
Figure 4.21: Connection Diagram…………………………………………………77
Figure 4.22: Data Acquisition Dal08 Program…………………………………….78
Figure 4.23: Sonic Viewer Model 5217A…………………………………………82
Figure 4.24: Zero adjustment of waveform display………………………………..84
Figure 4.25: Software 3D Slicer for image processing…………………………….87
Figure 4.26: Reduce picture noise and improve visual comprehension……………87
Figure 5.1: Work flow of matrix acidizing experiments results in this chapter…….88
Figure 5.2: Extracted plug samples with a diameter from the core section……….89
Figure 5.3: Photomicrographs for the two cored sections of the Mishrif reservoir’s
well Ad-12 (a) for sample 1 ; (b) for sample 6….………………….….90
Figure 5.4: XRD test of plug# 6 before acid injection……………..………………91
Figure 5.5: Typical core flood experiment of plug# 5……………………………..94
Figure 5.6: Four core flooding tests on sample # 1………………………………..95
Figure 5.8: Real record of acid injection for plug#6, time versus pressure drop….100
Figure 5.9: Photographs top-view of plug samples after acid injection (left-hand side
is the inlet face and the right-hand side is the outlet face)……………………….101
Figure 5.10: The propagation effectiveness of wormholes determining in the
laboratory by graphing acid injection rate versus pore volume…………….……103
Figure 5.11: Picking the PV(bt-opt) and vi-opt parameters………………….……….105
Figure 5.12: The findings of the acid flooding test PVbt plotted as a function of the
vi. Data created by modeling using equation 5.10…………..…..……...107
Figure 5.13: Application of wormhole propagation global models to calculate the
wormhole radius versus time for well Ad-12……………………………109
Figure 5.14: Application of wormhole propagation global models to calculate the
skin factor versus time for Well Ad-12………………………………….114
Figure 5.15: CT scan for sample 1; (A) before acidizing; (B) after acidizing with
injection flow rate of 0.667 cc/min……………….……………………..112
Figure 5.17: 3D view of CT-scan at different angles to illustrate wormholes' passage
through plug sample 3……………………………………….…………..113

14. viii
Figure 5.18: 3D view of CT-scan at different angles for sample 7 after acid treatment
with flow rate injection of 0.667 cc/min…………………..…...………...114
Figure 5.19: Primary and shear velocity for the core sample at different cases (dry ,
wetted and acidized)…………………………………………………….116
Figure 5.20: Bulk density versus the primary velocity acid treatment…………..117
Figure 5.21: density versus the shear velocity before and after acid treatment….117
Figure 5.22: Prior and post acid treatment relationships between the velocity of
compressional waves (VP) and effective porosity……………………….………118
Figure 5.23: Prior and post acid treatment relationships between the velocity of shear
waves (Vs) and effective porosity……………….………………………119
Figure 5.24: Front panle of Ultasonic measurements for plug 1, (a) & (b) is the
primary wave record prior and post acid, respectively, …….…………...121
Figure 5.25 Representative waveforms recorded in a plug sample No.1 for (a) the P-
wave pulses………………………......………………………………….122
Figure 5.26: Primary wave forms of plug# 5, the recorded time in microsecond....123
Figure 5.27: Young's modulus pre- and post-acid treatment of rock samples……125
Figure 5.28: Poisson's ratio pre- and post-acid treatment rock samples………….125
Figure 5.29: Coefficient of lateral earth pressure at rest (Ko) values pre- and post-
acid treatment rock samples…………………………..…………………126
Figure 5.30: Material index pre- and post-acid treatment of rock samples………127
Figure 5.31: Daily Acidizing report for Well Ad-12……………………………..130
Figures 5-32 to 5-38: Acidizing analysis Stimpro Output. ………………….133-138
Figures 5-39 to 5-53: Reservoir Simulation and Production Analysis………139-152

15. ix
LIST OF TABLES
Table 1-1: The formation pore pressure, fracturing pressure and strength were
obtained based on sonic log. ……….…………………………………..13
Table 3-1: Core flooding at high temperatures studies with various acid systems have
distinct experimental features and outcomes……………………………..31
Table 3-2: The parameters of the reaction rate HCl acid with calcite……………..36
Table 3-3: Linear, radial (cylindrical), and spherical……..……………………….50
Table 5-1: Mineral composition of target formation and experimental core samples
obtained using XRD………………………………………………..…….90
Table 5-3: Lists the dimensions and weights of dry and wet core samples……….92
Table 5-4: The pore volume, bulk volume, and effective porosity calculated from the
observed values………………………………………………………..…93
Table 5-5: Basic properties of gelled acid………………………………..………..96
Table 5-6: Examined the volumetric dissolving capability of acids…..………..…98
Table 5-7: All the required data from actual lab experiments and observations in the
field for well Ad-12……………………………………………………..108
Table 5-8: Field reported data for the stimulated wells the build-up test………...111
Tables 5-9 to 5-18: Acidizing parameter for Stimpro input………………….131-132

16. ix
NOMENCLATURE
𝐴 = Cross-sectional area perpendicular to the wormhole front.
𝐶 = Acid concentration.
𝑐t = Total formation compressibility.
𝐷A = Acid species diffusivity coefficient.
𝑑 = General linear dimension, such as a diameter or a general “scale.”
𝑑core = Core diameter
𝑑e,wh = Equivalent wormhole cluster diameter, parameter in the Furui et al. (2010)
model.
𝑑rep,1 = Parameter of the proposed wormhole global model; representative
scale up to which there is a decrease in 𝑃𝑉bt, opt
𝑑rep,2 = Parameter of the proposed wormhole global model; representative
scale up to which there is a decrease in 𝑣i, opt
𝑑s1 = Scale related to the decrease in 𝑃𝑉bt, opt
𝑑s2 = Scale related to the decrease in 𝑣i, opt
ℎ = Reservoir thickness, net pay
𝐽 = Productivity or injectivity index
𝑘 = Permeability (scalar)
𝑘c = Mass transfer coefficient
𝑘eff = Effective mass transfer coefficient, including reaction and mass
transfer effects
𝐿 = Wellbore length
𝐿rep,1 = Parameter of the proposed wormhole global model; representative
length up to which there is decrease in 𝑃𝑉bt, opt in radial geometry
𝐿rep,2 = Parameter of the proposed wormhole global model; representative
length up to which there is decrease in 𝑣i, opt in radial geometry
𝑙perf = Perforation length
𝑙wh = Wormhole length in a linear geometry
𝑁AC = Acid capacity number
𝑃𝑉bt = Pore volumes to breakthrough, in wormhole propagation
𝑃𝑉bt, opt = Optimum pore volumes to breakthrough, in wormhole propagation
𝑃𝑉bt, opt core = Optimum pore volumes to breakthrough in the core scale, in
wormhole propagation

17. x
𝑝 = Pressure
𝑝w = Wellbore pressure
𝑞 = Flow rate (injection or production rate)
𝑞c = Heat flux from the reservoir in the heat transfer analysis
𝑟e = External radius of a drainage region
𝑟w = wellbore radius
𝑟wh = Radius of cylindrical wormholed region
𝑟wh,rep,1 = Parameter of the proposed wormhole global model; representative
radius of the wormholed region up to which there is a decrease in
𝑃𝑉bt, opt in radial geometry
𝑟wh,rep,2 = Parameter of the proposed wormhole global model; representative
The radius of the wormholed region up to which there is a decrease in
𝑣i, opt in radial geometry
𝑠 = Skin factor
𝑇 = Temperature
𝑡 = Time
𝑣i = Interstitial velocity
𝑣i, opt = Optimal interstitial velocity, in wormhole propagation
GREEK
α= Exponent relating wormhole growth with time (𝑟𝑤ℎ ∝ 𝑡𝛼)
αz=Parameter in the model by Furui et al. (2010)
β100= Acid gravimetric dissolving power (of the pure, 100% acid)
𝜀1 = Parameter of the proposed wormhole model; exponent relating
decrease in 𝑃𝑉bt, opt as the scale increases
𝜀2 = Parameter of the proposed wormhole model; exponent relating
decrease in 𝑣i, opt as the scale increases
𝜂 = Parameter of the specific surface area evolution model
𝜅 = Thermal conductivity
𝜌acid = Acid solution density
𝜌f = Fluid density
𝜇 = Fluid dynamic viscosity
𝜙 = Rock porosity

18. Introduction

19. 1
Chapter :1 Introduction
1.1 Preface
Global oil demand will continue to rise between 2018 and 2024 (Figure 1.1),
with the bulk of the growth coming from transportation and aviation and the
petrochemical and residential/commercial/agricultural sectors. Net extra
demand in 2024 is estimated to climb by 1.5 mb/d over 2018 (OPEC, 2019).
Consequently, oil and gas wells are stimulated routinely to expand
production and maximize recovery. Hydraulic fracturing may be a more
expensive option; however, matrix acidizing is extensively used because of
its cheap cost and ability to restore the original productivity of damaged
wells and provide additional production capacity. The overall reserves of
sandstone and carbonate reservoirs are increased due to acidification, which
improves eventual recovery.
Figure 1.1: Global oil demand between 2018 and 2024 (OPEC, 2019)

20. 2
1.2 Research Motivation
Acidizing is one of the most frequently utilized stimulation techniques used
in the petroleum industry (American Petroleum Institute, 2014). Several
reports have been issued on the difficulties encountered during the
stimulation operation of the Ahdeb oil field, particularly for the development
of the Mishrif reservoir, including: (a) high injection pressures, which make
it difficult to inject acid into the reservoir formation; and (b) only a few acid
jobs have been effective in Ahdeb oil wells, while the bulk of the others has
been unsuccessful. This deposit's significant failure rate of oil well
stimulation necessitates more investigations. As the oil and gas industry
works to progressively extract hydrocarbon reserves contained in low
permeability carbonate formations and intercrystalline sandstone, several
concerns have arisen, including the best methods for drilling and completing
horizontal and vertical wells in these systems, as well as the best procedures
for hydraulic or acid fracture of these formations to produce oil (Bennion,
Thomas and Bietz, 1996). The Mishrif carbonate series stratigraphic
structure is depicted in Figure 1.2. Mishrif formation rocks can be divided
into the following groups based on rock lithology and facies (Al-Hashmi,
Qutob and El-Halfawi, 2010):
• In contrast to reservoir rocks, compact limestone does not contain
hydrocarbons that may be recovered. The porosity of this limestone
ranges from 0 to 8.01%, and it is impermeable.
• Despite of its low permeability, chalk limestone possesses tiny grains
and high porosity (about 20 percent) (1.5 md). Fine clay-impregnated
grains, moderate porosity (17%), and poor permeability characterize
Lagoon Limestone (3.7 md).

21. 3
• Reef limestone is divided into fine and intermediate grains and coarse
and intermediate grains. It has a high porosity (23%) and excellent
permeability(75md).
Figure 1.2: Mishrif carbonate layers stratigraphic structure (Al-Waha Pet. Corp. Ltd.,
2010a).
Accordingly, enhancing existing reservoir performance should be a priority
concern, particularly in chalk and Lagoon limestone. Dissolving or
constructing new channels through these rocks with limited permeability by
well stimulation procedures improves the amount of oil extracted. Hydraulic
fracturing and matrix acidification are the two most often employed methods
of stimulation the formation.
1.3 The Aim and significance of the study
For matrix acidizing treatments, acid is injected below the fracking pressure
to prevent fractures from being produced during the treatments, aiming to
improve permeability in the wellbore area rather than significantly
influencing the reservoir. The acid reacts within a few inches of the wellbore
in sandstones and a few feet of the wellbore in carbonates. The complete
resource of Lagoonal and Chalk limestone is around 33%, which cannot be
extracted using traditional production techniques. Consequently, other

22. 4
stimulation strategies such as matrix acidification must be researched.
Developing a new core flooding system from scratch that operates safely and
reliably is one of the research objectives to displace various fluids under a
wide range of conditions. As a result, this innovative system effort will
execute a core flooding to acidify the matrix. Additionally, this research
includes instructions for conducting testing and troubleshooting solutions for
equipment. Furthermore, we will investigate the experimental work to
explore the effect of acid treatment on the geomechanical parameters of the
Mishrif reservoir's Mi4 unit. The propagation of acid-induced wormholes
and their influence on the rock strength must be analyzed and compared to
intact rocks. Consequently, a CT scan will be performed to determine the
size and shape of the channel (wormholes) created. The data of CT will be
processed to provide 3D images that can be used to precisely characterize
the sample's wormhole shape, direction, and distribution. Additionally, we'll
perform numerical simulations using licensed software and compare them to
experimental data to achieve our goal. Understanding carbonate acid
treatment will be gained, enabling the complete design and implementation
of acidizing operations in the Mishrif reservoir.
Research's significance may be summarized and indicated in the following
points:
• The Ahdeb matrix acidizing has never been studied before; therefore,
this work will provide new information on limestone acidizing in Mi4.
• Due to various damage surrounding the wellbore, many oil wells need
acidizing at least once throughout their lifecycle.
• The results will demonstrate the significance of using the optimal
injection rate while acidifying the matrix.

23. 5
• It is critical for wormhole formation during matrix acidization that
mineralogy and pore size distribution be considered.
• This research will evaluate the impact of matrix acidizing treatment
on acoustic characteristics, which is never investigating before.
• CT-Scan applications in matrix acidizing will be investigated in this
research; furthermore, this will construct 3D representations of the
wormhole extension via CT-processing software.
1.4 Fieldwork and data collection.
After appropriate approval from the Petroleum Research and Development
Center, Midland Oil Company, to collect the necessary data for the current
research, they authorized a 1.5-meter section from the Mi4 unit of the
Mishrif formation in well Ad-12, an oil-producing well; we could recover 11
plug samples from this section. The logging data from the Ahdeb field is
collected, along with the final well report, geological report, and stimulation
report from the same formation.
1.5 Geological Setting
In the early 1980s, the Ahdeb oil field was discovered in Wasit province,
Figure 1.3. The 2D seismic acquisition for the explored area took place in
1977. Nine exploratory wells have been drilled and analyzed systematically
in the oil-bearing region. Eight of them were showing a flow of oil. The
deepest well was Ad-1, which reached Ratawi formation at a depth of
4057.0m, Lower Cretaceous(Al-Waha Pet. Corp. Ltd., 2010a). In the Middle
of the Cretaceous period, five pay zones were discovered. These pay zones
are Khasib-2, Mishrif-4, Rumaila-1, Mauddud-1, and Rumaila-2b. The
anticline is elongated from NWW to SEE. There are three high points within

24. 6
the anticline: wells 1, 2, and 4. The well one peak is somewhat higher than
the well two and well four peaks (Al-Baldawi, 2020). The field is an
integrated structure, and no flaws were discovered. The anticline has a
modest relief, usually between 55 and 70 meters. The anticline's two sides
are not steep.
Figure 1.3: Ahdeb Field Location Map (Al-Waha Pet. Corp. Ltd., 2010a).
Well Ad-12 is intended to evaluate the five pay zones and construct the
Khasib-2 layer close to Well Ad-1 (Figure 1.4). The main target (Khasib-2)
is anticipated to be -2615m to 20m TVDSS in this well. The reservoir
pressures are expected to be approximately 4422.8 psi, close to the original
field pressure. The total depth (T.D.) of the Ad-12 is -3123,9 m (3140m
MD). The first projected risk production rate for Ad-12 is moreover 1320
bbl/d (The average rate in the first month)(Al-Waha Pet. Corp. Ltd., 2010a).
Ahdeb Oil Field

25. 7
Figure 1.4: AD-012 Contour Map showing the Well Location (Al-Waha Pet. Corp. Ltd., 2009).

26. 8
1.5.1 Formation Summary
The major oil-bearing formations in the Ahdeb field include the upper
Cretaceous Khasib formation, Mishrif, Rumaila, Mauddud formations, and
the middle Cretaceous Mishrif, Rumaila, and Mauddud formations. Oil
reserves are buried at depths ranging from 2600m to 3300m. Laterally, the
Khasib formation's oil-bearing zone spans the whole field, whereas the
Mishrif, Rumaila, and Mauddud formations' oil-bearing zones are primarily
located in the eastern portion.
1.5.2 Main Lithologic Characteristics
The Ahdeb Oil field's formations are marine sedimentary, with large sets of
limestone, marl, bioclastic limestone, and local dolomite developing large
groups of limestone, marl, bioclastic limestone, and local dolomite, mainly
bioclastic limestone rock, grains are very small, primarily calcite mud
crumbs, particle size generally less than 0.3mm, content is 50% to 70%. The
phenomena have a content of 10- 28 percent echinoderms, brachiopods,
foraminifera, algae, and other biological debris, and a tiny quantity of sand
dust, dust, and recrystallization grain of dolomitization is also visible
(Sadooni, 1996).
1.5.3 Formation Tops
Originally, there were nine wells in the Lower Cretaceous in the Ahdeb
oilfield. The un-penetrated Cretaceous well Ad-1 is the deepest, with a TD
of 4057 m. According to Iraq's stratigraphic classification, the penetrated
section may be divided into 18 formations (Figure 1.5) (Al-Waha Pet. Corp.
Ltd., 2010a). Marine facies dominate the Paleogene and Cretaceous systems,
whereas continental-oceanic interaction facies and land facies dominate the
Neogene and Quaternary. The following are their key lithologic features:

27. 9
The Hauterivian, Barrem, Aptain, and Albian stages are primarily found in
the Lower Cretaceous. By lithologic and electric logging characteristics, the
Albian stage (Mauddud formation) may be split into five numbers, the most
important of which is the intercalation of lower interval velocity and lower
natural gamma with high interval velocity and high natural gamma.
Interbedded with intercalation gray, gray-green, soft-plastic mdianarl, and
shale strips in the middle-lower portions is predominantly gray, off-white,
soft-hard limestone, abundant stylolite, and intercalation gray, gray-green,
soft-plastic mdianarl, and shale strips. Brown, hard dolomite, and limestone
dominate the upper section, with bioclastic limestone interbedded with marl
strips and shale strips on the top. The unit has a range of 300-320 meters.
Cenomanian, Turonian, lower Coniacian-lower Santonian, and upper
Companian-Maestrick stages are all found in the Upper Cretaceous.
Rumaila, Ahmadi, and Mishrif formations are located on the Cenomanian
stage (Al-Waha Pet. Corp. Ltd., 2009).

28. 10
Figure 1.5: Stratigraphic Column of Ahdeb Field (Al-Waha Pet. Corp. Ltd., 2010a).
System Stage Group Section Thick Depth
(m)
AC
120 40
GR
-50 100
lithology
RT
0.1 1000
DEN
1.95 2.95
Petrographi
下中新统
Oligocene
Mid-Upper
Eocene
Lower
Eocene-
Paleocene
Upper
Cretaceous
Lower
Cretaceous
Upper
Companian
Lower
Coniacian
Turonian
Senomanian
Albian
Aptian
Barremian-
Hauterivian
Lower Fars
Jerbe/Eup
U.p.Kirkuk
Dammam
Aliji
Shiranish
Hartha
Sadi
Tanuma
Khasib
Mishrif
Rumaila
Ahamadi
Mauddud
Nahrumr
Shuaiba
Zubair
Ratawi
K1
K2
K3
K4
Mi1
Mi2
Mi3
Mi4
Mi5
Ru1
Ru2a
Ru2b
Ru3
Ru4
AH
Ma1
Ma2
Ma3
Ma4
Ma5
127－194
266－316
160－191
47－61
168－213
110－126
53－63
102－115
96－116
235－247
30－36
177－219
86－102
105－138
1500
1600
1700
1800
1900
2000
2100
2200
2300
2400
2500
2600
2700
2800
2900
3000
3100
3200
3300
3400
3500
3600
3700
3800
3900
4000
4100
4200
4400
4500
The lower part consis
dolomite and semi-plastic
pyrite. The middle part c
and sandstone interlayere
marl. The upper part cons
medium to good roundness,
cemented with calcareous,
and limestone stripes in
Brown, soft to hard l
with black spotted oil-be
lower part.The middle par
with white limestone with
and with muddy interlayer
with grey,soft to hard, p
glauconite,fossils and da
chert nodules.
Grey soft to hard lim
glauconite and fossils.
Greenish, soft to har
with argillaceous limesto
Lower part consists w
porous limestone. At midd
white shaly limestone. Th
with brown, white, soft t
The lower part mainly
soft to hard limestone se
embedded with marl. At th
consist with white, grey
Grey, greyish green l
embeddedwith soft to hard
Mainly consists with wh
and embedded with chalk sed
part mainly consists with b
limestone sediments with fo
and with various extent oil
Lower part consists w
and embedded with chalk a
part is off-white limesto
with mud and shale stripe
part mainly white plastic
Upper part mainly con
hard limestone sediments
oil-immersion, embedded w
Middle-lower parts mainly
off-white, soft to hard p
sediments,partly embedded
recrystallization dolomit
Grey marl sediment em
Mainly consists with
soft to hard, well sortin
part with pyrite embedded
brown shale.
In middle- lower part
off-white, soft to hard l
stylolite, embedded with
to plastic marl and shale
Mainly consists with
soft to hard, well sortin
part with pyrite embedded
brown shale.
The top part mainly c
in part) porous dolomite,
oil spot and embedded wit
shale stripe.
The middle part consi
white dolomite and limest
with shale stripe.
Lower Group mainly co
dolomite with pyrite and
Lower forma
yellow,green mu
grained sandsto
greyish brown m
fossile and lim
pyrite, silty s
Soft to hard yellow b
with sandyspherulite, con
crumbs. Thesediment grain

29. 11
1. The Ahmadi formation is primarily gray, soft-hard marl interbedded
with shale strips, with a thickness of 33 meters and stratigraphic
stability within the studied region.
2. The Rumaila formation may be divided into five strata using electric
characteristic correlation, with a total thickness of 240 to 250 meters.
The middle and lower parts are compensated by limestone strata
characterized as soft-hard porous, off-white, and partially interbedded.
In the higher section, soft-hard limestone strata and medial oil-
impregnation are interbedded with intercalation chalk.
3. Mishrif formation: the bottom layer is brown, soft-hard porous
limestone interbedded with dolomite and chalk sediments; the middle
area is chalk, off-white limestone, and clay and shale strips in part;
and the top level is largely soft-plastic gypsum sediments with shale.
The thickness of the unit ranges from 90 to 110 meters.
1.5.3.1 Reservoir Properties
The highest porosity is 30.2 %, the average porosity is 17.3 %, and the
maximum permeability is 317.6 md; the average permeability is 2.5 md,
according to test results from core samples. With increasing burial depth,
porosity diminishes. The Ahdeb oil field's reservoirs have a moderate
porosity but poor permeability. It is clear that the reservoirs are not uniform,
as they could be drawn from core and test data. However, due to the
inadequacy of well and seismic data, a better understanding of reservoir
heterogeneity is impossible for the time being. When additional data is
available, the relationships between lithology, property, and oil reservoir
distribution should be investigated further. Porosity decreases with burial
depth.

30. 12
1.5.3.2 Formation Pressure Prediction
The formation pore pressure, fracturing pressure, and strength were obtained
based on the sonic log. The result is introduced in Figure 1.6 and table (1-1).
The following table is found on the AD-010H*
.
Figure 1.6: Pressure profiles of Ahdeb (Al-Waha Pet. Corp. Ltd., 2010a).
*Waha company naming system: AD 1-5-2H ; AD mean Ahdeb, first number mean the number of dome,
second number mean number of profile on this dome and third number is the well number on this profile H
mean drilling type is horizontal.

31. 13
Table 1-1: The formation pore pressure, fracturing pressure, and strength were
obtained based on the sonic log. (Al-Waha Pet. Corp. Ltd., 2009)
1.5.4 Characteristics of Fluids
a. The saturation pressure is 2900 Psi on average, which is 60% of the initial
reservoir pressure. The reservoir is not fully drained.
b. The initial solution gas-oil ratio (GOR) is typically around 110m3
/m3
,
with dissolved gas energy. This energy might be employed in the early
stages of development.
c. Viscosity is low at initial reservoir pressure, 1.54 cp @ 4900 Psi.
Geological
Period
Formation
Pore
Pressure（Psi/ft）
Collapse
Pressure（ Psi/ft ）
Fracture
Pressure（ Psi/ft ）
Tertiary
Upper fars 0.446505 0.56355 0.62424
Lower. fars 0.46818 0.6069 0.6936
Jeribe/Eup 0.44217 0.58956 0.715275
UP. Kirkuk 0.45951 0.567885 0.74562
Dammam 0.44217 0.56355 0.77163
Aliji 0.446505 0.5202 0.7803
Upper
Cretaceous
Shiranish 0.45084 0.48552 0.793305
Hartha 0.46818 0.52887 0.79764
Sadi 0.498525 0.489855 0.801975
Tanuma 0.51153 0.489855 0.801975
Khasib 0.50286 0.52887 0.793305
Mishrif 0.51153 0.515865 0.80631
Rumaila 0.498525 0.5202 0.82365
Ahamadi 0.51153 0.489855 0.827985
Mauddud 0.481185 0.49419 0.83232

32. Literature Review

33. 14
Chapter: 2 Literature review
Acidizing regarded as the oldest in terms of well stimulation techniques,
whereas hydraulic fracturing is a more recent invention. By 1890, HCl had
been used to induce fracture in limestone formations for the first acid jobs. A
scale-removal procedure called acidizing was developed in the 1930s, as were
corrosion inhibitors (Syed A. et al., 2016).
Since oil and gas exploration has relied on carbonate rocks for so much of
its history, it is no surprise that around 60 % of global reserves are found in
these rocks (Burchette, 2019). According to current estimates, carbonate
reservoirs are thought to hold more than 60 % of the oil reserves globally and
40 % of the world's natural gas reserves. Particularly, the carbonate fields in
the Middle East account for around 70 % of total oil moreover to 90 % of total
natural gas reserves (Schlumberger, 2021). The chemical composition of
carbonates allows for successful acid injection stimulation despite variations
in porosity and permeability depending on the location of its deposit. In both
basic and practical terms, the chemical interaction between a fluid and the
porous media through which it travels is of interest. The porous solid is carved
with flow channels as the reactant dissolves the medium. Flow conditions and
response rates influence the structure and behavior of dominating channels.
An understanding of porous media channeling is required in order to forecast
reaction zone or dissolution zone movement (Hoefner & Fogler, 1988).
Physical or chemical techniques might achieve this objective. Various
substances are used in the chemical reduction of reactivity in order to prevent
a fast reaction from occurring. Several researchers investigated the
mechanism of acid-rock reactions, acidizing fluid efficiency, acid flow back
mechanism, acid leakoff, and the acidizing models (iAljawad et al., 2020;

34. 15
Ghommem eti al., 2015; iGomaa et al., 2018; N. Li et al., 2015; iLungwitz et
al., 2007; iYoo et al., 2018; iZhang et al., 2020; iZhu et al., 2015). While others
investigated the resulting effect of acid treatment on the mechanical rock
structure (Zhang et al., 2020) and the influence of the rock mineralogy on
acidizing efficiency (Martyushev et al., 2022).
2.1 Early Studies of Acid treatment for Mishrif Formation.
It was observed that 28 % HCl acid with fluid loss additives was required for
vuggy core samples, whereas 28 % HCl (retarded) was needed for chalky core
samples (Morrica, 1981) in his experimental study of the promotion of Mishrif
formation in Halfaya field.
(AGIP, 1986) investigated oil well stimulation and water injection wells in
the West Qurna field's Mishrif formation. The researchers' conclusion initially
stimulated the less permeable zone (MA) before moving onto, the more
permeable zone (MB).
Laboratory tests were carried out by (Al-Taii, 1988) to study the impact of
acid concentrations and various additions on the acidification of matrix
samples from the Mishrif formation. It was determined that the optimal acid
and additive concentration yielded the best results and acceptable corrosion
rates for steel.
2.2 Acid–Mineral Reaction Stoichiometry
By injecting acids into the wellbore, matrix acidizing has been routinely
employed to increase well productivity. Acid spreads throughout the rock by
forming wormholes, and channels with high permeability. Reducing the
thickness of the skin around the wellbore increases throughput. According to

35. 16
acidizing recommendations by industry, hydrochloric acid (HCl ) is the most
often utilized acid for carbonate reservoir matrix acidization (McLeod, 1984).
HCl is the acid of preference for acidizing techniques for most carbonate
formations. The base acid is usually combined with other acids such as
hydrofluoric (HF) in most sandstone applications (Alhamad et al., 2020).
The creation of wormholes in carbonate acidizing is essential to the
stimulating effect. Both the acid's reactivity and the rate at which it is injected
are critical to this process. In order to construct the most effective wormholes,
it is necessary to manage the diffusion and reaction rates of HCl and
carbonate. Interstitial velocity (vi) is often plotted against pore volume to
determine how deep a wormhole may go in a wellbore. The deeper the
wormhole goes, the deeper the wellbore is penetrated.
2.3 Models for the Optimum Matrix Acidizing Determination
Numerous scholars have studied wormhole formation during carbonate
acidification to understand the process better and predict the optimal
parameters for obtaining the best outcomes. The earliest model possibly is
introduced by (Schechter & Gidley, 1969), who proposed a model based on
the pore size distribution and its development due to surface reactivity.
(Daccord & Lenormand, 1987) proposed a model of wormhole radial
propagation based on this discovery, in which the wormholes expand in
accordance with the fractal dimension 𝑑𝑓 ≈ 1.6. A difficulty of this model is
that, while it may be excellent at interstitial velocities beyond the optimum
requirement, it fails for tiny, suboptimal velocities.
The inefficient and poor wormhole propagation is not taken into account. In
reality, it does not anticipate an ideal condition and predicts that 𝑟𝑤ℎ → ∞ as
𝑞 Approaches 0.

36. 17
Following that year, (Daccord et al., 1989) developed another model based on
the fractal character of the wormholing phenomena, establishing a
quantitative relationship between the best acidifying conditions. The
wormholed area has no pressure decrease because the wormholes are deemed
endlessly conducive compared to the original reservoir. Daccord et al.
demonstrated via radial propagation experiments that those wormholes form
a fractal structure having fractal dimension 𝑑𝑓 ≈ 1.6. Radius rises with
increasing time, as shown by the formula, 𝑟𝑤ℎ ∝ 𝑡𝛼
, where ∝≈ 0.7 for 2D
(thin) radial structures and with 3D radial structures the latter having a time
constant of ∝≈ 0.65. This translates a significant fact on wormhole
propagation: in these studies, the value of 𝑃𝑉𝑏𝑡 dropped as the wormholes
spread farther from the center. This would be the case if 𝑃𝑉𝑏𝑡 was constant,
as the injected acid volume is directly proportional to the wormholed volume.
In this situation, 𝑟𝑤ℎ would rise according to the √𝑡, so 𝛼 would be equal to
0.5. In actuality, 𝛼 = 0.65, which suggests that the wormhole propagation
grows more efficient as the wormholes propagate. In other words, the
effective 𝑃𝑉𝑏𝑡 diminishes as 𝑟𝑤ℎ grows. Hence, predicting the wormholed
area is needed to understand how the matrix acidizing treatment would affect
well performance.
Hill introduced and published the volumetric model in (Economides et al.,
1994). It is a very useful and basic model that assumes a constant value of
pore volume at breakthrough (𝑃𝑉𝑏𝑡). An intuitive model offers a
straightforward forecast of the wormhole length to use a single variable, 𝑃𝑉𝑏𝑡.
Using an average 𝑃𝑉𝑏𝑡 value or a constant interstitial velocity throughout
stimulation ensures accuracy since it implies a fixed value. Wellbore flow is

37. 18
radial in the near-wellbore area; thus, the interstitial velocity falls when acid
travels further from the wellbore. This causes the value of 𝑃𝑉𝑏𝑡 to fluctuate
with injection time, which isn't considered in the volumetric flow model.
(Fredd & Fogler, 1996a) demonstrated that the various dissolving patterns
correlate to certain Damköhler number ranges. The optimum injection
velocity relates to a Damköhler number of around 0.29 overall rocks, acids,
and even chelating agents studied. The ratio of net reaction rate to acid
transport rate via convection is known as the Damköhler number. In slow
reaction systems, including limestones and weak acids and dolomites with
many of these acids at low temperatures, the dissolution might be governed
by the rate of the reaction or the diffusion of the acid or the reaction products.
Damköhler's number explains the conflict between the dissolution rate
(including diffusion phases and reaction) and the acid convection rate.
At a slow injection velocity (high Damköhler number), the acid reacts before
being delivered by convection, resulting in face dissolving. When injection
velocities are too high (low Damköhler number), the acid is carried away by
convection before it has a chance to diffuse to the mineral surface and react,
resulting in very ramified wormholes or uniform disintegration. Convection,
diffusion, and reaction rates are perfectly balanced at the optimum Damköhler
number, and the acid is only delivered farther into the rock by convection,
resulting in a narrow wormhole.
Despite its intriguing theoretical implications, the presence of an ideal
Damköhler number is difficult to implement in acidizing process design due
to a large number of unknown factors (pore diameters and mass transfer
coefficients) involved in its computation.

38. 19
(Gong & El-Rabaa, 1999)'s model for radial wormhole propagation
incorporates the fractal dimension introduced by (Daccord & Lenormand,
1987) but uses a mix of dimensionless numbers to describe both the optimum
and inefficient wormhole propagation at lower flow rates. In fact, (McDuff et
al., 2010) utilized it to match data from tests with enormous blocks of
carbonates, the biggest wormhole experiments recorded to date, and it proved
to be an effective model. However, this model has a dimensional discrepancy:
the length computed does not have length dimensions, but rather a dimension
of a length unit to the power of (2/𝑑𝑓 ). Wormhole propagation requires d𝑓 ≈
1.6, not 2; hence this is not a length dimension. This is a theoretical
contradiction, and in reality, it also leads to misleading computations.
Calculating injection time to attain a certain wormhole length using this
approach, for example, yields a different answer when length units of various
lengths are use.
(Huang et al., 1999) proposed an alternative representation of the Damköhler
number. (M. A. . A. Mahmoud et al., 2011) introduced a Péclet number-based
model. (Dong et al., 2017) developed a novel model based on a statistical
study of pore size distribution. (Fredd & Fogler, 1996a) provided in-depth
analyses of wormhole models. These models were divided by the latter into
seven categories:
• Péclet number models.
• Damköhler number models.
• Capillary tube models.
• Transition pore theory models.
• Averaged continuum (or two-scale) models.
• Network models.
• Semi-empirical models.

39. 20
2.4 Growth and Formation of Wormhole Shown by CT-Scan
Several continuum models use the Darcy-Brinkman-Stokes equation and the
reaction equations and acid transport to simulate the porous medium as a
whole and keep track of how much acid is dissolved in the medium. As the
acid dissolves the rock, the porosity rises, and the model updates the
permeability, pore radius, and specific surface area of the rock to account for
the increased porosity. Numerous studies have used this concept (de Oliveira
et al., 2012; Fredd & Fogler, 1996b; Glasbergen et al., 2009; X. Liu &
Ortoleva, 1996; Maheshwari & Balakotaiah, 2013; Schwalbert et al., 2019;
Soulaine & Tchelepi, 2016). Several of these researchers (de Oliveira et al.,
2012; Maheshwari & Balakotaiah, 2013; Schwalbert et al., 2019) made
significant progress in calibrating the model to match the experimental results
acid efficiency curves.
Additionally, experimental research is devoted to determining the ideal state
by non-destructive measures (without dissolving cores). (Tansey, 2015)
created small-scale pore-network models using CT-scan images of cores to
mimic acid injection. He was able to see the creation of wormholes in the
modeling but did not properly forecast the ideal circumstances. (Zakaria et al.,
2015) performed tracer experiments to determine the relationship between
wormhole development and flowing percent. The procedure seems promising;
however, there are few outcomes yet.
(Al-Duailej et al., 2013; M. Mahmoud, 2017) employed Nuclear Magnetic
Resonance (NMR) to assess the interconnectivity of pores and wormholes and
to link it with the optimal flow rate. Although this is an intriguing approach,
the best findings need NMR analysis of the wormhole's structure, making it a
destructive measurement.

40. 21
High-resolution images of three acidized Indiana limestone core samples
from the (McDuff et al., 2010) investigation are displayed in Figure 2.1. For
Indiana limestone, the core plugs were chosen in accordance with the
wormhole efficiency curve at various acid flow levels, from the lowest to the
highest.
Figure 2.1: Three core samples of high-resolution CT scans (McDuff et al., 2010)
Despite extensive study and development, the most accurate values for
optimum pore volume at breakthrough (𝑃𝑉𝑏𝑡,𝑜𝑝𝑡) and inertial velocity at
breakthrough 𝑉𝑖,𝑜𝑝𝑡 are still acquired empirically by developing acid
efficiency curves through core flooding studies or by matching field data from
matrix acidizing tasks. Because of the significant correlation between 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡
and 𝑉𝑖,𝑜𝑝𝑡 and the diameters of the experimental cores, even experimentally
acquired curves should be utilized with care. This demonstrates the need to
scale laboratory experimental findings to field circumstances with caution
since the cross-sectional areas of the field treatments are many orders of

41. 22
magnitude greater than the cores utilized in the studies. One may argue that
the most trustworthy data would be historical matrix acidizing field data.
2.5 Impact of Acid on Mechanical Properties of Rocks
In radial acid treatment experiments of hollow chalk samples, (Walle &
Papamichos, 2015) showed that acidizing rock samples cause a reduction in
their mechanical strength; this was confirmed by comparing the mechanical
properties of the acid-treated rocks and the intact ones. Mustafa et al. (2022)
studied the impact of an acid wormhole on the mechanical properties of
carbonates (chalk, limestone, and dolomite); they showed that acidizing
reduces the hardness and elastic modulus of rock. The authors noted that
dolomite is the least impacted by acid treatment, while chalk samples were
the most affected. (Barri et al., 2016) investigated the effect of acidizing using
chelating agents (ethylenediaminetetraacetic acid (EDTA) and
diethylenetriaminepentaacetic acid (DTPA)) on the mechanical properties of
carbonate rocks. The outcome shows that elastic properties of weak
carbonates (such as Austin chalk) were most affected, while hard rocks such
as Indiana limestone were not significantly affected. Zhou et al. (2021)
experimentally researched fracture surface strength before and after acid
treatment. The authors argued that several reported mechanical deteriorations
of carbonate after acid etching could not be applied to evaluate fracture
conductivity since such investigations provide information on the mechanical
rock properties of the rock mass rather than the surface of the fracture. They
emphasize that fracture surface strength measurement data before and after
acid etching is necessary for fracture optimization and conductivity evaluation
of the acidizing job. The simulation work of Li & Shi (2021) also showed that
acid fluid fracturing could alter rock strength.

42. 23
There can be no doubt that the acid dissolution of rock minerals would modify
the rock structure, the mineralogy, as well as the mechanical properties of the
artificial fracture surface (M. Liu & Mostaghimi, 2017). Therefore, acidizing
often leads to rock mechanical properties modification around the wormhole,
improving or impairing reservoir quality. A notable body of literature reported
rock weakening due to acidizing as reservoir impairment. However, rock
loosening may mean the establishment of flow paths by acid dissolution of
rock and consequent wormhole propagation into the reservoir.
2.6 Design of Carbonate Matrix Acidizing
Acidification has been studied mathematically using a variety of models,
including the dimensionless model, the capillary tube model, the network
model, and the continuum model (Fredd & Fogler, 1996a; Gdanski, 1999;
Hung et al., 1989; Maheshwari & Balakotaiah, 2013; Schecter & Gidley,
1969). Acidization and dissolution patterns, as determined by 1-D and 2-D
numerical simulations, as well as experimental research by (Bazin et al.,
1999), are illustrated in Figure 2.2 in a qualitative comparison. According to
Figure 2.2, 1-D numerical simulations anticipate greater optimal acid injection
rates and larger pores to breakthrough (PVBT) than 3-D numerical
simulations. A variety of disintegration patterns cannot be predicted using 1-
D numerical simulations (such as conical, wormhole, and ramified). The
transport and reaction factors impacting dissolution may be gleaned through
1-D numerical simulations, which are computationally cheap. Some of the
dissolution patterns seen in the laboratory may be anticipated using 2-D
computational models; however, these models cannot predict the optimal
injection rate and PVBT. Consequently, in order to accurately forecast the
experimental outcomes, we will need to use 3-D numerical simulations. It's

43. 24
been a while since any 3-D numerical studies have been done to understand
better the dissolving process (Cohen et al., 2008; de Oliveira et al., 2012;
Ratnakar et al., 2012). On the other hand, HCl is a fast-acting acid, and these
studies may not be able to anticipate its findings accurately.
Figure 2.2: Dissolution patterns generated by 1-D, 2-D numerical simulations and
experimental research by (Bazin, 2001)were compared to acidization curves (Panga et
al., 2002).
(McDuff et al., 2010) was able to use high-end numerical simulation
models created from the 3-D digital representation of a well's whole 3-D shape
to explore how wormhole changes occur over time. An advanced gridding
method is used to mesh both the near-well rock matrix and the void space
inside the wormholes. Figure 2.3 illustrates how multi-phase flow simulations
may be carried out.

44. 25
Figure 2.3: Simulation of wormhole flow characteristics using numerical methods
(McDuff et al., 2010).
The findings of this research may be used to improve the recovery of oil
from the Mishrif reservoir. Known as "stimulating treatments," these
techniques pour acid into wells in order to dissolve part of the porous rock
surrounding the wellbore, increasing its permeability or flow capacity.
Following stimulation, the channels created by dissolution allow for easier
movement of oil out of the reservoir.

45. Theoretical
Background and
Research
Methodology

46. 26
Chapter :3 Theoretical Background and Research
Methodology
3.1 Preface
The term "formation damage" refers to a reduction in the permeability of the
original rock as a consequence of some alteration, such as clay swelling, fines
migration, particle clogging, or changes in wettability. Due to scale
precipitation, asphaltene deposition, and other causes, formation damage may
also occur throughout the productive or injective life of the well.
Matrix acidizing treatments restore damage to the formation caused by earlier
well operations. The ultimate objective of these treatments is often to restore
the original formation's permeability. On the other hand, a matrix acidifying
treatment may significantly enhance the formation process in sandstones and
shales. The permeability may be considerably improved to values much larger
than the initial permeability, up to a distance of possibly tens of feet from the
wellbore.
Consequently, while hydraulic fracturing is usually projected to provide better
results in sandstones or shales than matrix acidizing in carbonate rocks, both
procedures are competitive. More work is required to determine the most
effective option.
As described as a technique of well stimulation, matrix acidizing involves
introducing an acid solution into the formation to dissolve a few minerals
present and, as a result, restore or increase permeability around the wellbore,
among other things (Economides et al., 2013). Due to the low velocity of the
acid injection, the pressure is maintained below the formation breakdown
pressure, and as a result, the reservoir rock does not fracture (Figure 3.1).

47. 27
Figure 3.1: Comparison between fracture and matrix acidizing (re-edited by adding the
pressure vs. injection rate) (Leong & Ben Mahmud, 2019).
The fracture acidizing might fail to boost the well performance because the
acid unevenly etches the fracture walls as it moves along the crack. Moreover,
if pressure is removed and the fracture heals, the high fluid flow conductivity
of the fracture will be preserved owing to uneven etching. Acid-fracturing
treatments may also yield wormholes, however undesired, as they promote
fluid leakage and reduce the etched fracture length. As a result of this
treatment, any damaged regions will be bypassed, and in many cases, a highly
negative skin factor will be created. Acid stimulation is often used in
carbonate deposits because it is simple and inexpensive, clearly illustrated in
Figure 3.2.

48. 28
Figure 3.2: Acid Injection through a Perforated Completion Results in Wormholes.
3.2 Stimulation type selection
Well productivity may be improved by determining the value of enhancing
well productivity and the likely reasons or sources of formation damage after
the well has been recognized as underperforming. The next step is for the
engineer to decide on a course of action. If the issue is in the well design or
operation (e.g., artificial lift or the size of the tube), then stimulation is not
recommended, and the equipment should be updated or fixed instead. Targets
well's Performance must be balanced, i.e., no more should be produced than
can be transported by tubing or lift or processed by facilities. As a result, the
economics of skin effect gradual improvement may be compromised. It is
important to analyze the influence of the skin effect on the economic limit and
the recovery of the reserve. Candidate selection and stimulation methods are
aided by a decision tree (Figure 3.3). The productivity achievement
determines the stimulation approach. To meet the productivity objective,
matrix stimulation should provide a skin effect of 10 % of the initial damage
skin effect for sandstones and 2 to 3 % for carbonates. Aside from hydraulic
fracturing, there is no other stimulation method for sandstone reservoirs. Acid
fracturing may be cost-effective to boost productivity in carbonate reservoirs

49. 29
(limestones or dolomites). In both circumstances, the reservoir experiences a
hydraulic fracture (Economides & Nolte, 2000).
Figure 3.3: Candidate selection and Stimulation Methods(Economides & Nolte, 2000)
3.2.1 Acid Type compatibility to the treatments
The desire to utilize acid to enhance oil and gas flow to the wellbore has
existed from the early days of its utilization. After a useful corrosion inhibitor
was discovered in the early 1930s, acid became generally used. Though a
variety of organic and inorganic acids had been explored by this point, HCl
had become the acid of choice. For (Wilson, 1935)'s work, the most surprising
feature comes from recognizing the harm caused by acid-soluble solids
clogging. A year later, Halliburton attempted to use hydrochloric and

50. 30
hydrofluoric acid to treat sandstone for the first time, but the treatment was
unsuccessful, and Halliburton did not use this method for the following 20
years.
When Dowell Service first launched the "renowned" "Regular Strength Mud
Acid" mix in the late 1930s, its primary goal was the elimination of wellbore
drilling mud filter cake. For correct acid treatment design, McLeod laid forth
the foundations in 1984 based on formation mineralogy, a critical problem
that is frequently disregarded.
Various acidizing fluids such as self-diverting acid (Bazin et al., 1999;
Lungwitz et al., 2007), visco-elastic surfactant (VES) acid, gelled acid, self-
generated acids, and recently, chelating agents (Tariq et al., 2021) have been
developed and investigated both in the laboratory and in field-scale (Gou et
al., 2021; Hassan & Al-Hashim, 2017; Isah et al., 2021; Lai et al., 2021; Li &
Shi, 2021; Melendez et al., 2007; Taylor & Nasr-El-Din, 2001). In the acid
treatment of naturally fractured carbonate formation, VES acid forms more
complex fractures compared to self-generated acid and gelled acid.
However, gelled acid can decrease rock’s breakdown pressure to a large
extent (up to 57% less than that caused by water fracturing); this increases
fracture propagation and enhances efficiency (Gou et al., 2021). Moreover,
gelled acid creates larger fractures than crosslinked acid and consequently
weakens the rock's mechanical properties more than crosslinked acid (Lai et
al., 2021). Stimulation success depends on the length and width of these
wormholes (Al-Arji et al., 2021). Thus, a successful acid treatment operation
requires that the wormhole propagates deep into the formation. The
investigations show in Table 3.1 of core flooding at higher temperatures using
a diversity of acid systems with various experimental characteristics and
results.

51. 31
Table 3-1: Core flooding at high temperatures studies with various acid systems have
distinct experimental features and outcomes (Chacon & Pournik, 2022).
At a temperature of 394.26 K, the injection of HCl led to a conical channel
and the dissolving of the core face. As a result, it needed a comparatively high
PVBT of 4.25. In addition, greater optimum injection rates are necessary for
an efficient acidizing treatment since the acid is expended faster at high
temperatures. The necessity for an acid that retards the acid reaction, needs
lower injection rates, leads to dominating wormholes, and reduces corrosion
rates is the most important consideration in high-temperature conditions.
(Huang et al., 2003) using 15 % acetic acid and injecting it at a velocity of
2.2x10-8
m3
/s found a PVBT of 9.1 at a temperature of 394.26 K. Wormholes

52. 32
in HAc system have considerable branching, but the main wormhole is the
dominating wormhole. It has been shown that organic acids are more
expensive than HCl for dissolving an equal quantity of rock. Because it has a
greater acidity than other organic acids like acetic and formic,
Methanesulfonic acid (MSA) has been suggested as a stand-alone stimulating
fluid. MSA is a good alternative to organic acids since it possesses soluble
reaction products, is less corrosive, and is hazardous in small quantities.
However, it's a hefty price tag. In order to determine the most cost-effective
acid system, experimental research (Ortega, 2015) was undertaken to find the
ideal acid mix of HCl and MSA.
There are several aspects to consider when selecting an acid, including
pressure, temperature, formation permeability, hydrocarbon composition, as
well as compatibility between acids and additives. Figure 3.4 workflow chart
of significant innovations have been necessary to overcome the most
prevalent carbonate matrix acidizing difficulties. In high-temperature
formations, this problem is exacerbating since the reaction rate rises with
temperature. HCl's rapid chemical reaction rate with carbonates rocks results
in the need for a large amount of acid in acidizing treatments. Due to the quick
interaction of HCl with the formation, it does not generate effective
wormholes since it does not have enough time to penetrate far into the
medium, resulting in more uniform disintegration. Additionally, it was shown
at high temperatures when decreasing the injection rate to maximize contact
time resulting in face dissolving, an inefficient structure for acidifying
treatments (Chacon & Pournik, 2022). Due to the above challenges, an acid
that slows down the acid reaction and reduces corrosion rates must be used to
overcome these obstacles.

53. 33
Figure 3.4: Work flow chart of selection the optimal acid to overcome the most
prevalent carbonate matrix acidizing difficulties.
Challenges in
carbonate matrix
acidizing
Acid retardation
for HPHT
conditions
Surfactant-Based
Emulsified Acids
Cationic Surfactant-
Based Polymer-
Assisted Emulsified
Acid
Non-Ionic
Surfactant-Based
Emulsified Acids
Organic Acids
Methanesulfonic
Acid
Acetic Acid
Especialized Gelled
Acid
Biopolymeric Resin-
Based Retarded HCl
Diversion for
heterogeneous
formations
Polymer-Assisted
Emulsified Acid
Viscoelastic
Surfactant-Based
Acid
TN-16235
VES and Foam-
Based VES
Corrosion control for
corrosive
environments
Organic Corrosion
Inhibitors
Alcohol Based
Inhibitors: Propargyl
and Furfuryl Alcohol
QMQTPH
Natural Extracts As
Corrosion Inhibitors
Henna Extract
Aqueous Garlic Peel
Extract

54. 34
3.3 Design of the Stimulation Treatment Sequence
The order in which the fluid patches are applied and their precise time are
critical considerations for devising a stimulation treatment. Each well has
been damaged uniquely, necessitating a new approach to repair. After the
procedure, the pre-and-post flush phases are the most common parts of a
treatment sequence. It is important to know how much cement, clays, and
other pore-filling minerals are present in the sandstone before acidizing (Allen
& Roberts, 1978). As a first treatment, a combination of hydrochloric and
hydrofluoric acid is often used.
The next section will explain why a Preflush is so important. We need to know
where the formation is physically located before deciding whether or not to
apply acid system diverting or retarding chemicals. Acid type selection is
simplified in carbonate reservoirs.
3.3.1 Preflush
Preflushes of hydrochloric acid are used to prepare or condition the formation
that will be stimulated so that the acid will be accepted in the most favorable
parts. The primary goal of the Preflush is to displace the brine from the
wellbore to prevent contact between the hydrofluoric acid and the formation
of brine, which contains potassium, sodium, and calcium, which causes
precipitation(Prouvost & Economides, 1989).
3.3.2 Main (Acid) treatment
This stage's goal is to repair the well's damage. The appropriate injection rate
is determined by the acidizing task matrix's acidizing or acid fracturing type.
In carbonates, wormhole propagation speed increases with injection rate, so a
high injection rate is required for rapid wormhole propagation. When

55. 35
acidizing in areas of high-water saturation, low pump rates are also advised.
The maximum permitted pressure for the tubing, the surface equipment, and
the pump must be considered to determine whether the formation can
withstand larger forces (Economides et al., 1994).
3.3.3 Postflush (overflush)
The overflush moves the primary acid flush at least four feet away from the
wellbore (Economides & Nolte, 2000). Since retarded acid's reaction time on
creation is longer than its injection period, it might aid in acid penetration.
Instead of using potassium chloride as a post flush in acidizing sandstone
formations with hydrofluoric acid, ammonium chloride, NH4Cl, is advised.
3.4 HCl acid carbonate reactions
Hydrochloric acid (HCI) and carbonate minerals react due to a hydrogen ion
(H+) interaction with the mineral. When HCI is dissolved in water, it virtually
completely dissociates into hydrogen and chloride ions (Cl). (Cohen et al.,
2008; Fredd & Fogler, 1998; Hoefner & Fogler, 1988) were consulted to
calculate how HCl interacts with calcite and dolomite. In summarizing their
outcomes, (Wang et al., 1993) came to the following conclusion about the
reaction rate (𝑟HCl) for HCl with different minerals:
−𝑟HCl = 𝐸𝑓𝐶HCl
𝛼
(3.1)
𝐸𝑓 = 𝐸𝑓
0
𝑒𝑥𝑝⁡ (−
𝛥𝐸
𝑅𝑇
) (3.2)
The constants α, 𝐸𝑓
0
, and
𝛥𝐸
𝑅𝑇
are given in Table 3-2. The units are used in
these expressions is international system unit, so 𝐶HCl has units of kg-
mole/m3
, and T is in K.

56. 36
Table 3-2: The parameters of the reaction rate of HCl acid with calcite and dolomite
rocks. (Economides et al., 1994)
Mineral 𝛼 𝐸𝑓
0
[
𝑘𝑔⁡𝑚𝑜𝑙𝑒𝑠⁡𝐻𝐶𝑙
𝑚2 − 𝑠 − (𝑘𝑔 − 𝑚𝑜𝑙𝑒𝑠
𝐻𝐶𝑙
𝑚3 𝑎𝑐𝑖𝑑⁡𝑠𝑜𝑙𝑢𝑡𝑖𝑜𝑛)
𝛼]
𝛥𝐸
𝑅𝑇
(𝐾)
Calcite
(CaCO3)
0.63 7.55x103
7.314x 107
Dolomite
(CA Mg
(CO3)2)
6.32⁡𝑥⁡10−4
𝑇
1 − 1.92⁡𝑥⁡10−3𝑇
7.9x103
4.48x105
By deriving the kinetics of a weak-acid carbonate mineral reaction from the
kinetics of an HCl reaction (Schechter, 1992).
−𝑟weak acid = 𝐸𝑓𝐾𝑑
𝛼/2
𝐶weak acid
𝛼/2
(3.3)
where Kd is the weak acid's dissociation constant and Ef is the HCl–mineral
reaction's rate constant. Taking into account mass transfer effects, (M. Buijse
& Glasbergen, 2005) take a more comprehensive method to the total reaction
rate of carbonate minerals with the weak acids.
Hydraulic fracturing and matrix acidizing are the two most often used
stimulation methods. It is possible to boost oil and gas production using
hydraulic fracturing, which involves injecting fluids at a pressure greater than
the failure pressure of the reservoir. Acids have been used to improve the
permeability and porosity of the carbonate and sandstone formations around
the wellbore via acidizing. (Ituen et al., 2017). An increase in the permeability
of the reservoir is achieved by dissolving minerals like dolomite and quartz in
the rock, which leads to a rise in the flow rate of hydrocarbon fluids from the

57. 37
formation to the wellbore. In sandstone stimulation, acidizing and fracturing
processes have their benefits and disadvantages (Shafiq et al., 2018).
Carbonate formations have a fundamentally different acidifying mechanism
than sandstones. Clastic formations have slow surface reaction rates, and an
acid front passes over the porous medium homogeneously. The fact that
carbonates have very high surface reaction rates means that mass transfer
often limits the overall reaction rate, resulting in dissolving highly non-
uniform patterns. Due to the non-uniform dissolving of limestone by HCl in a
big block experiment, wormholes, as illustrated in Figure 3.5, are created.
(McDuff et al., 2010).
Figure 3.5: In a Large-Scale Block Experiment, Wormholes were Generated (McDuff et
al., 2010).
The shape of these wormhole patterns is determined by several variables,
including mass transfer rates, reaction kinetics, flow geometry, and injection
rate. Figure 3.5, CT scans of wormholes produced in core floods demonstrate
how the wormholes change from enormous, conical-shaped tubes at low
injection rates to considerably narrower wormholes with few branches at

58. 38
moderate injection rates and eventually to a highly branched morphology at
high injection rates. Experiments like this demonstrate optimum conditions
for acid injection for every carbonate rock and acid combination that result in
the longest wormholes possible with a given amount of acid. Compared to the
rock's initial permeability, all of the dissolution structures in Figures 3.6 and
3.7 are deemed indefinitely conductive.
Figure 3.6: At the top is CT-scan for different injection rates required to created
wormhole (Fredd & Fogler, 1996), while below is the wormhole morphologies at
different injection rates (Sharif, 2019)
Hence, the optimal dissolving pattern to acquire in an acidizing matrix
technique is the one that reaches furthest into the reservoir for a set quantity
of injected acid. The dominating wormhole is an example of this ideal
structure. Due to the narrowness of the channel, it takes the lowest amount of

59. 39
acid to form. As a result, a certain amount of acid injected may penetrate
deeper into the formation.
Figure 3.7: Morphologies of wormhole at various rates of injection introduced by
(McDuff et al., 2010)
Equations (3.4) and (3.5) indicate the straightforward chemical dissolution of
carbonates by acids for limestone and dolomite, respectively.
2𝐻𝐶𝑙⁡ +⁡𝐶𝑎𝐶𝑂3 ⟶⁡𝐶𝑎𝐶𝑙2 ⁡+ 𝐶𝑂2 ⁡⁡+⁡𝐻2𝑂 (3.4)
4𝐻𝐶𝑙 + 𝐶𝑎𝑀𝑔(𝐶𝑂3)2 ⁡⟶⁡𝐶𝑎𝐶𝑙2 + 𝑀𝑔𝐶𝑙2 ⁡+ ⁡2𝐻2𝑂⁡ + ⁡2𝐶𝑂2 (3.5)
3.5 Optimal Injection Rate
According to several studies, there is an acid-flow rate-dependent minimum
quantity of acid necessary to propagate wormholes across the core for a
particular rock/acid system and temperature (Fredd & Fogler, 1996; Hoefner
& Fogler, 1988).
HCl injection into limestone results in the wormholing activity seen in Figure
3.8. A wormhole's volume of acid grows extremely slowly if the flow rate is

60. 40
above the optimal; if the flow rate is below the optimum, the quantity of acid
needed to propagate a particular distance decrease rapidly as the injection rate
increases. This suggests that injecting at a rate greater than the optimal is
preferable to inject at a rate excessively low (M. Buijse & Glasbergen, 2005).
Figure 3.8: A laboratory study of the propagation efficiency of wormholes (M. Buijse &
Glasbergen, 2005)
Pore Volumes to Breakthrough (𝑃𝑉𝑏𝑡) are defined as the acid volume injected
in the core sample during the experiment to develop the wormholes after
breakthrough, divided by the initial volume of the core's pore; it is a
dimensionless quantity. Equation (3.6) specifies that this is a crucial
parameter:
𝑃𝑉𝑏𝑡 =
𝑉𝑎𝑐𝑖𝑑,𝑏𝑡
𝜙𝑉𝐵
(3.6)
where 𝑉𝑎𝑐𝑖𝑑,𝑏𝑡 denotes the volume of acid injected up to the breakthrough
point, VB represents the core sample’s bulk volume utilized in the experiment,
and 𝜙 means the porosity of specimen. Pore volume at the breakthrough
(𝑃𝑉𝑏𝑡) is a critical metric for predicting the result of matrix acidizing

61. 41
treatments since it allows for the calculation of the depth to which wormholes
penetrate for a given amount of acid injected.
The interstitial velocity (𝑣𝑖)⁡is calculated by dividing the volumetric rate (𝑞)
by the cross-sectional area of the flow multiplied by the porosity (2𝜋𝑟𝑤ℎ𝜙).
Thus,
𝑣𝑖 =
𝑞
2𝜋𝑟𝑤ℎ𝜙
(3.7)
3.6 Wormhole Propagation Global Models
Typically, the optimal matrix acidizing conditions may be determined by a
series of flooding experiments in the laboratory. Since each point on the curve
necessitates a full-scale experiment of core flooding, this is a time-
consuming and costly procedure.
Theoretical approaches to wormhole propagation modeling exist; however,
they are difficult to apply in the actual field. Therefore, the presumed global
models are often utilizing for field size treatment planning. Wormhole
propagation rates may be predict using macroscopic semi-empirical models
based on data collected around a wellbore (Economides et al., 2013).
(M. Buijse & Glasbergen, 2005) suggested an empirical correlation that fits
the acid efficiency curve of 𝑃𝑉𝑏𝑡 vs. 𝑣𝑖 (Figure 3.8), using as input just the
coordinates of the optimal point, 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡, and 𝑣𝑖,𝑜𝑝𝑡. Its appearances a great
correlation to match experimental data, and it has been employed by various
studies. (M. Buijse & Glasbergen, 2005) also suggested a strategy to leverage
the correlation in the radial geometry, which consists of computing the
interstitial velocity as an average at the front of the wormholed zone.
The only parameters needed for this model are the coordinates of the ideal
point on the acid efficiency curve: 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and 𝑣𝑖,𝑜𝑝𝑡. For interstitial
velocities that are either too high or not perfect, this curve exhibits the same

62. 42
form as what has been found experimentally. The radius of the wormholed
zone may then be estimated using by integrating the velocity over time.
The Buijse and Glasbergen model was used as a foundation for Tardy's novel
concept of self-diverting acids. They also offered a version of Buijse and
Glasbergen's model consisting of increasing that model's 𝑃𝑉𝑏𝑡 by a constant.
The mechanism for upscaling from linear flow and core scale to field size and
radial flow provided by (Tardy et al., 2007) is the same as proposed by Buijse:
utilize the same correlation of 𝑃𝑉𝑏𝑡⁡versus 𝑣𝑖, with 𝑣𝑖 computed as the average
at the wormhole front.
(Talbot & Gdanski, 2008) suggested another model based on Buijse's but
taking other factors into consideration, such as acid content, temperature, and
core aspect ratio. They offered a mechanism to transform 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and 𝑣𝑖,𝑜𝑝𝑡
data recorded with a specific temperature and acid concentration to another
temperature and acid concentration. Length of core divided by cross-sectional
area is used to calculate the aspect ratio in their model. But they do not offer
any way to cope with this aspect ratio when upscaling from core size and
linear flow to field scale and radial flow.
Wellbore scale calculations are carried out using the 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and 𝑣𝑖,𝑜𝑝𝑡 values
acquired in core flooding tests (with cores measuring from 1 inch to a few
inches) in Buijse' model and its adaptations. Even the core scale
measurements, as previously indicated, alter dramatically when the diameter
of the core varies. Hence, it should be predicted that values of 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and
𝑣𝑖,𝑜𝑝𝑡 typical for the full wellbore will differ from those recorded using cores.
The reported values of 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and 𝑣𝑖,𝑜𝑝𝑡 are strongly reliant on the diameter
of the cores employed to measure them; hence, the influence of core size is an
essential but sometimes overlooked element of wormholing research.

63. 43
According to (M. A. Buijse, 2000), both 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and 𝑣𝑖,𝑜𝑝𝑡 decrease in
diameter with increasing core diameter, as illustrated in Figure 3.9 of the
experimental findings utilizing varied core diameters. With the exception of
core diameter, all other characteristics of the samples are the same for all
pieces, including length, acidity, comparable porosity, mineralogy, and
permeability. Some examples of acid-rock combos: ( Furui et al., 2010)
utilized 28 % HCl, and high porosity, ( Buijse, 2000) employed 5 % HCl and
limestone cores and (Dong et al., 2014) utilized 15 % HCl and Indiana
limestone.
Figure 3.9: Data comparing the core dimension of 𝑷𝑽𝒃𝒕,𝒐𝒑𝒕 and 𝒗𝒊,𝒐𝒑𝒕 reported in the
literature(Dong et al., 2014).

64. 44
According to (Economides et al., 2013), three global models are the
most often used: (M. Buijse & Glasbergen, 2005)'s model, Economides'
volumetric model, and (Furui et al., 2012c)'s model. In addition to (Daccord
et al., 1989), (Tardy et al., 2007) and (Talbot & Gdanski, 2008), many more
global models may be used for comparison.
3.6.1 The Volumetric Model
To figure out how much acid is required to move wormholes a certain
distance, the simplest method assumes that a certain percentage of the rock
punctured will dissolve in the acid. This notion, known as the volumetric
model, was first introduced by (Economides et al., 1994).
As a few wormholes are constructed, only a small percentage of the rock is
dissolved; as more branching wormhole structures are developed, a bigger
matrix fraction is dissolved. The radius at which a wormhole may propagate
is
𝑟𝑤ℎ = √𝑟𝑤
2 +
𝑉
𝑃𝑉𝑏𝑡𝜋𝜙ℎ
(3.8)
The 𝑃𝑉𝑏𝑡 is the only wormhole propagation parameters needed for this
concept in equation 3.8, which may be obtainable from core-flood
experiments.
3.6.2 The Buijse-Glasbergen Model
The empirical model of wormhole propagation proposed by (M. Buijse &
Glasbergen, 2005) is based on the typical dependency of the 𝑃𝑉𝑏𝑡 in acid core
floods on the interstitial velocity. There is a constant functional relationship
between wormhole propagation velocity and the 𝑃𝑉𝑏𝑡 for various rocks and

65. 45
different acid systems. They came up with a function to represent this reliance
based on this premise. Using the Buijse and Glasbergen model, we can say
𝑣𝑤ℎ =
𝑑𝑟𝑤
𝑑𝑡
= (
𝑣𝑖
𝑃𝑉𝑏𝑡−opt
) (
𝑣𝑖
𝑣𝑖−opt
)
−𝑦
{1 − exp 〈−4 (
𝑣𝑖
𝑣𝑖−opt
)
2
〉}
2
(3.9)
By simply stating the ideal condition, the minimum pore volumes to
breakthrough ⁡(𝑃𝑉𝑏𝑡−opt) value and the optimal interstitial velocity 𝑣𝑖−opt
value; therefore, the 𝑃𝑉𝑏𝑡−opt–𝑣𝑖−opt relationship may be conveniently
established. A single calibration point is required to fit this model to a specific
acid-rock system.
The wormhole velocity is determined by the 𝑣𝑖−opt at the wormhole front,
𝑟𝑤ℎ, and decreases as the wormhole area front advances away from the
wellbore.
3.6.3 The Furui et al. Model
(Furui et al., 2012b) suggested a new semi-empirical model, based on the
correlation by Buijse and Glasbergen (2005), but with a unique upscaling
approach to describe the wellbore size. In this model, the values of 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡
and 𝑣𝑖,𝑜𝑝𝑡 at the field scale are different from those observed at the core scale,
and they are not constant, changing during the acid treatment as wormholes
propagate. The assumption of computing interstitial velocity as the average of
the stimulated region's outer area was also adjusted. Observing that the flow
rate is concentrated at the ends of the dominating wormholes via tests and
numerical simulations, they argued that what drives the wormhole
propagation velocity is not the average interstitial velocity⁡𝑣̅𝑖, but the
interstitial velocity at the tip 𝑣𝑖,𝑡𝑖𝑝⁡of the wormholes, which is significantly
more than the average value, particularly at the field scale.

66. 46
𝑣wh = 𝑣𝑖, ip 𝑁𝐴𝑐 × (
𝑣𝑖, ip
𝑣𝑖, tip,opt
)
−𝛾
× {1 − exp⁡ [−4 (
𝑣𝑖, ip
𝑣𝑖, ip , opt
)
2
]}
2
(3.10)
(Furui et al., 2012a) extended their work and published equations for 𝑣𝑖,𝑜𝑝𝑡
for the spherical and radial wormholes propagation. The first is suited for the
acidizing open-hole or highly perforated wells when the radial flow field.
After that, they upgraded the equation to be acceptable for acid injection from
small sites far apart, such as when a limited entry approach is used with a very
modest perforation density when presumed a spherical flow from each hole.
This model predicts a larger wormholing velocity by linking it with the
interstitial tip velocity and guesses a slower falling rate of that velocity. Furui
et al. models predict that for radial wormhole propagation, for example, 𝑣𝑖,𝑜𝑝𝑡
decreases proportionally to
1
√𝑟𝑤ℎ
for⁡α𝑧 = 0⁡or⁡does⁡not⁡decline⁡at⁡all⁡(for⁡α𝑧 = ⁡1),
whereas the Buijse-Glasbergen model estimates that 𝑣̅𝑖 rises proportionally to
1/√𝑟𝑤ℎ.
These models were utilized by (Furui et al., 2012a & Furui et al.,2012b) and
shown to be more accurate with field data than the Buijse-Glasbergen model
using 𝑃𝑉𝑏𝑡,𝑜𝑝𝑡 and 𝑣𝑖,𝑜𝑝𝑡 measurements obtained in a laboratory. It does,
however, include other changeable factors, such as α𝑧⁡, mwh and de,wh, which
have been found to be difficult to predict. Eventually, these factors should also
be historically matched.
A fascinating model, developed by (Furui et al., 2012b), considers the results
collected at various scales and has been effectively used to match field data.
But there are a few drawbacks: (1) it requires input parameters such as
wormhole cluster diameter and wormhole count that are difficult to measure
or estimate; (2) the predicted field results can change when data from different

67. 47
core sizes are used as input; and (3) it does not reverse back to the Buijse and
Glasbergen correlation when representing core scale.
3.6.4 Wormholed Region (Radial/Cylindrical)
Suppose the completion of the well to be acidized is an open-hole or
perforated casing with a high perforation density. In that case, the acid is
anticipating to follow the radial flow field around the well.
In radial flow, the skin factor of a cylindrically stimulated zone surrounding a
well with changed permeability can be calculated using an equation
introduced by (Hawkins, 1956). (Daccord et al., 1989; Economides et al.,
2013) apply the Hawkins formula with the assumption that
𝑘
𝑘𝑤ℎ
< 1, hence
(
𝑘
𝑘𝑤ℎ
− 1) ≈ −1, determines the skin factor resulting from a matrix acidized
carbonate if k is the original reservoir permeability and kwh is the permeability
of the wormholed zone.
Typically, the radius of the wormholed zone, rwh, is approximated using a
global model, such as the volumetric model of Buijse- Glasbergen, or Furui
et al.’s model.
3.6.5 Divergence and heterogeneous rock types.
The majority of carbonate rocks are heterogeneous and exhibit large
permeability differences, complicating implementing treatments of matrix
acidizing (Pereira et al., 2012). The wormholes in the more permeable zones
become longer, while those in the less permeable zones get shorter.
Fluid placement or diversion procedures are the approaches to cope with this
challenge and boost the acid penetration in the limited permeability zones
(Economides et al., 2013). Heterogeneous distribution of wormhole