matrix acidizing in carbonate reservoir

Kurdistan Reginal Government
Ministry of Higher Education
Knowledge University
College of Engineering
Petroleum Engineering Department
4th
stage graduation project
Matrix acidizing in carbonate reservoir
A thesis submitted in partial fulfilment of the requirements for the award of
Bachelor’s Degree in Petroleum Engineering
Prepared By:
Mohammed Ammar
Abduladheem Abdullah
Supervised By:
Mr. Sarhad Ahmed
May 2017

i
Declaration
This dissertation was carried out by Mohammed Ammar and Abduladheem Abdullahin
partial fulfillment of the award of Bachelors’ degree in petroleum engineering at the
Knowledge University for the academic year 2016-2017.
The title of the project is Matrix acidizing in carbonate reservoir prescribed by the college of
engineering.
Mr Sarhad Ahmed
(Project Supervisor)
Date: 20th
May 2017
Place: Kurdistan-Erbil

ii
Acknowledge
We are grateful to the God for the good health and wellbeing that were necessary to complete
this graduation project
We place on record, our sincere thank you to Dr.Taleb Dean of the Faculty, for the
continues encouragement.
We are also grateful to Mr. Sarhad Ahmad , lecturer, in the Department of petroleum
engineering. We are extremely thankful and indebted to him for sharing expertise, and
sincere and valuable guidance and encouragement extended to us.
We wish to express our sincere thanks to Dr. Falah Hussein Khalaf , head of the
department, for providing us with all the necessary facilities for the research.
We take this opportunity to express gratitude to all of the Department faculty members for
their help and support. We also thank our parents for the unceasing encouragement, support
and attention.
In the end, do not forget to thank the Committee precious because it gave us enough time to
discuss about the project in addition to the important advice and guidance.

iii
Abstract:
The acidizing is pumping of the acids into the wellbore to remove near well formation
damage and other damaging substances, matrix acidizing is applied primarily to remove skin
damage that caused by drilling, completion, work over, well killing or injection fluids.
This project is concerned with carbonate reservoirs that exceeded in Kurdistan subsurface
formations.
Conduct a case study using real industrial data of Arab-D formation (Ghawar oil field – Saudi
Arabia) which has five water wells were treated with 50 gallon of HCl acid The treatment
acid was placed with coiled tubing and foam was used as diverter. The foam was made from
nitrogen, water and surfactants.
Water injection pressure, injection rate and injection flow meter profiles prior to and after the
treatment for the five wells show optimistic results to an acceptable extent
In coiled tubing acid placement, the coiled tubing/borehole annulus is usually filled with acid
which allow the acid to be in contact with the entire zone at bottom hole temperature
condition. This reduces the degree of diversion effectiveness.
Recommend people who work in carbonate reservoirs they should done their work on
petrophsical analysis and the porosity should not have exceeded by the acids

iv
Table of Contents
DECLARATION _____________________________________________________________ I
ACKNOWLEDGE___________________________________________________________ II
ABSTRACT: _______________________________________________________________III
TABLES OF FIGURES: ________________________________________________________V
TABLE OF TABLES: _______________________________________________________ VII
CHAPTER 1: INTRODUCTION__________________________________________________ 1
1.2 INTRODUCTION ___________________________________________________________ 2
1.1 AIM AND OBJECTIVES:_______________________________________________________ 4
CHAPTER 2: ACIDIZING STIMULATION _________________________________________ 6
2.1 TYPES OF MATRIX ACIDIZING __________________________________________________ 6
2.1.1 Acid washing or wellbore clean out. __________________________________________6
2.1.2 Matrix acidizing _______________________________________________________7
2.1.3 Fracture acidizing. ____________________________________________________ 11
2.2 ACIDS USED IN ACIDIZING STIMULATION. _________________________________________ 13
2.2.1Mineral acids (HCl and HF) ______________________________________________ 13
2.2.2 Organic acids. _______________________________________________________ 17
2.3 ACIDIZING STIMULATION ADDITIVES. ____________________________________________ 17
2.3.1 Corrosion inhibitors. ___________________________________________________ 17
2.3.2 Surfactant.__________________________________________________________ 18
2.3.3 Anti sludge agents. ____________________________________________________ 18
2.3.4 Suspending agents ____________________________________________________ 19
2.3.5 Chelating or sequestering agents.___________________________________________ 19
2.3.6 Reducing agents ______________________________________________________ 20
2.3.7 Clay stabilizers ______________________________________________________ 20
CHAPTER THREE __________________________________________________________ 22
MATRIX ACIDIZING OF CARBONATE FORMATIONS _______________________________ 22
3.1 INTRODUCTION __________________________________________________________ 22
4.2 CARBONATE ROCK COMPOSITION AND THEIR REACTIONS WITH ACIDS: ______________________ 24
3.3 ACID DISSOLVING POWER: ___________________________________________________ 26
3.4 ESTIMATION OF THE REQUIRED ACID VOLUME FOR CARBONATE MATRIX ACIDIZING:______________ 28
3.5 OPTIMIZATION OF THE ACID INJECTION PRESSURE AND RATE: ____________________________ 31
3.5.1 Determination of the formation fracture gradient: ________________________________ 31
3.5.2 Acid injection rate: ____________________________________________________ 32
4.5.3 Maximum allowable surface injection pressure: _________________________________ 33
3.6 USING COILED TUBING TECHNOLOGY FOR ACID PLACEMENT AND DIVERSION IN MATRIX ACIDIZING OF
ARAB-D FORMATION (GHAWAR OIL FIELD – SAUDI ARABIA) WATER INJECTION WELLS: _____________ 33
3.6.1 Job evaluation:_______________________________________________________ 34
3.6.2 Coiled tubing with foam diversion: __________________________________________ 35
3.6.3 Coiled tubing acid placement with rotating side jetting nozzles _______________________ 37
CHAPTER 4: CONCLUSION AND RECOMMENDATION _____________________________ 40
CONCLUSION ______________________________________________________________ 40
RECOMMENDATION _______________________________________________________ 41
REFERENCES _____________________________________________________________ 42

v
Tables of figures:
Figure 1: Stim CADE.................................................................................................................9
Figure 2: Scanning Electron Microscope photogragh of Significant Clay Minerals..............10
Figure 3: Chart for Determining Uncorrected Acid Concentrations......................................16
Figure 4: Density Correction for HCL and HF Concentration...............................................16

vi
Figure 5: Water Injection Profile After Matrix Acidizing for Well (H) in Arab-D Formation
(Ginest et al., 1993) .................................................................................................................36

vii
Table of tables:
Table 1: McLeod acid use guidelines (McLeod, 2007, p.289).................................................23
Table 2: Solubility of Carbonate and Siliceous Minerals in Acids (Allen and Roberts, 1993, p.
7-18).........................................................................................................................................25
Table 3: Molecular Weight of Acids Used in Carbonate Matrix Acidizing (Cholet,2000,
p.205) .......................................................................................................................................27
Table 4: Molecular Weight of Minerals of HCL Reaction with Dolomite and Calcite
(Williams, Gidley and Schechter, 1979, p.13) .........................................................................27
Table 5: Water Injection Rate and Pressure Changes, in Arab-D Formation Water Injection
Wells, After Matrix Acid Treatment with Using Foam Diverter (Ginest et al., 1993).............37

Chapter 1: Introduction
1Matrix Acidizing
CHAPTER 1: INTRODUCTION

2Matrix Acidizing
1.1 Introduction
To identify the damage or plugging solids that must be removed by a solvent, you must be
familiar with the main types of damage that occur in oil, gas, and water wells. Oil well
damage usually occurs during drilling, cementing, perforating, gravel packing, production,
acidizing, well workovers, chemical treatments, and injection operations. Conventional
matrix acidizing in carbonate reservoirs uses hydrochloric acid to remove formation damage
and stimulate well performance. Many experimental and theoretical studies in carbonate
acidizing have confirmed the existence of an optimal acid injection rate at which major
wormholes are formed, and the benefit from stimulation is maximized. This optimal rate
depends on reservoir conditions, rock properties and chemical reaction rate. The success of
conventional matrix acidizing in carbonate reservoirs with hydrochloric acid is often limited
due to rapid acid spending at low injection rates to prevent fracturing the formation rock. The
injection of hydrochloric acid into carbonate formations at low rates results in compact
dissolution, or face dissolution of the carbonate matrix near wellbore, which consumes large
volume of acid and stimulates a short distance. studies have also shown that the acidizing
process is most efficient (defined as the process that will enhance near-wellbore permeability
to the greatest depth with the smallest volume of acid) when major wormholes develop.
Damage by whole mud or formation clays may be removed by appropriate HF treatments for
sandstones and HCl treatments for carbonates. Damage by cement filtrate (which usually
contains calcium hydroxide or forms of calcium silicate) is reduced by good fluid-loss control
in the cement slurry. Calcium hydroxide may be removed with either acetic acid or HCI.
Calcium silicates must be removed with HF. Damage may be severe when perforating
overbalanced in the wellbore (hydrostatic pressure in the well bore is higher than reservoir
pressure). Permeability around the perforated hole may be reduced to from 2 to 20% of
original permeability, depend in~ on the nature of the perforating fluid. Overbalanced
perforating will reduce permeability by compacting and plugging pores with crushed
formation fines, perforating debris, and contaminants in the perforating fluid. Perforation
damage usually is removed with HF in sandstone formations or with HCl in carbonate
formations.

3Matrix Acidizing
Damage to a producing well can be caused by formation movement, scale formation
(precipitated solids, and casing leaks. Whole formation production (collapsed perforations)
can occur in weak or friable sands. This may be corrected by gravel packing or some other
method of effective sand control. Fines migration also can occur. Fines can move through the
reservoir and bridge at or near the perforations to cause in-situ filter cakes (plugging) inside
the large pores in the sand. When casing leaks occur, either incompatible formation waters or
drilling mud residues may contaminate the perforated interval. Casing leak damage usually is
treated with HF for sandstones or HCl for carbonates. If acid is bullheaded down tubing into
a formation, pipe dope and/or iron scale (mill scale) may be squeezed into the formation with
the acid. The first acid that enters the formation already may have spent itself on iron oxide
scales. Formations with either high concentration of iron minerals or low permeability and
abundant clay also can be damaged by acid injection. Formations can be damaged easily by
improper use of HF. Spent HF will precipitate silica, calcium fluoride, and other compounds,
especially when not enough HCl preflush is used to remove calcium carbonate in the
formation prior to pumping the HF.
Scale inhibitors can oil wet carbonates and corrosion inhibitor treatments can oil wet
sandstones. Damage cannot be prevented when these treatments are necessary to keep the
well in operation; however, some inhibitors cause more damage than others. Variable degrees
of damage have been observed in corrosion inhibitor treatments of gas wells. Atomized
nitrogen treatments seem to be less damaging than oil squeezes when injecting corrosion
inhibitors in gas wells. Sometimes severe damage may be corrected by using tested
solvent/surfactant wash treatments.

4Matrix Acidizing
1.2 Aim and objectives:
Aim:
analyzing the matrix acidizing in carbonate reservoir
Objectives:
1.describe the brief introduction of matrix acidizing in carbonate reservoir.
2.presenting the literatures about the acids and application of acids in carbonate reservoir.
3.conduct a case studies using in industrial of petroleum engineering and describing the
results with conclusion

5Matrix Acidizing
CHAPTER 2: LITERATURE REVIEW

Chapter Two: Literature Review
6Matrix Acidizing
Chapter 2: Acidizing stimulation
2.1 Types of matrix acidizing
2.1.1 Acid washing or wellbore clean out.
The purpose of a chemical stimulation treatment, be it based on acid, solvent, or other
systems, is to remove formation damage and increase productivity/injectivity, by restoring or
improving the reservoir permeability in the near-wellbore region and in the wellbore .
A fundamental preliminary step in most successful matrix stimulations is a tubing cleanout
commonly referred to as a pickling treatment. A tubing pickle is often necessary to remove
mill scale, rust and other iron deposits from the tubular walls, in order to prevent their
injection into the reservoir with detrimental effects to permeability.
Acid washing is often necessary to remove mill scale, rust and other iron deposits from the
tubular walls, in order to prevent their injection into the reservoir with detrimental effects to
permeability. The pickling treatment also prevents the spending of the subsequent chemical
treatment; the creation and injection of damaging precipitates; and the formation of iron-
induced sludge in the reservoir.
Common pickling solutions include corrosive hydrochloric or acetic acid. Additionally, the
pickling solution often contains a hazardous organic solvent and surfactants to remove
asphaltene or wax deposits and damaging pipe dope residues.
Damage, or potential damage to perforations, tubing and the area immediate to the wellbore
caused by formation fines, mud or cement filtrate, scale and debris from well operations may
be removed by exposing the well to acid over a period of time (soaking), followed by some
form of agitation.
Acid can be circulated across the open-hole or perforated interval using coiled tubing,
allowing a short soaking period. The coiled tubing string is worked up and down through the
interval, and the spent acid is returned through the annulus. A second method is to apply
pressure against the perforations, followed by rapid release of pressure by opening the bleed-
off valve at the pumping unit a method known as back surging. This technique is primarily
effective when the reservoir pressure is greater than the fluid hydrostatic pressure. A further

7Matrix Acidizing
approach involves spotting acid across the perforations and swabbing back, either through
tubing or casing.
2.1.2 Matrix acidizing
Matrix acid treatments are pumped at pressures lower than the formation parting, or
fracturing, pressure to ensure removal or bypass of the damage in the pore spaces and to
leave zone barriers intact. These treatments are applied primarily to remove skin damage and
to improve formation permeability by dissolving acid-soluble solids.
In matrix acidizing, the intent is to improve or to restore the permeability of the region very
near the wellbore (a radius of 8 to 24 in. [20.3 to 61 cm]) without fracturing the producing
formation.
The purpose of matrix acidizing in cased and perforated wells in a carbonate reservoir is to
create wormholes that extend the effective wellbore drainage area.
There have been many laboratory studies on wormhole propagation influenced by
fluid-rock interaction chemistry and treatment design (volume, concentration, and injection
rate). All the experimental work conducted in the industry inject acid or other reactive fluid
into small core samples. The core faces are kept open during fluid injection. The perforating
effect is ignored. Under such testing configuration, the rock dissolution pattern goes from
face dissolution to dominant wormhole, wormhole ramification, and eventually a more
uniformed dissolution as the ratio of flow rate to reaction rate increases.
Rock dissolution patterns generated by reactive fluid injection are controlled not only by the
chemistry and the fluid velocity, but more so by the heterogeneity of the rock. In a carbonate
reservoir, the heterogeneity occurs from the deposition and diagenic processes through the
geological time.
In a cased-hole completion, perforations provide the communication between the wellbore
and the reservoir. They are the conduits for treatment fluid injection and reservoir fluid
production. For natural completions, the perforating job is designed with the goal of by-
passing the drilling damage in mind by creating deep and clean perforations.

8Matrix Acidizing
In low permeability reservoirs, perforating as deep as possible and cleaning up the
perforations as much as possible may still not be enough to generate the required
productivity, and it is common that the wells are stimulated immediately after perforated.
A conventional way of thinking is that when the well requires stimulation, creating deep and
clean perforations is not important because stimulation can extend the wellbore access far
past the damage. So the only goal of perforations is to provide the holes through the casing
and cement.
However, there have been cases showing that perforation cleanup plays an important role in
minimizing post stimulation skin. Furthermore, it is the belief of the authors that the
stimulation treatment process, e.g. injection rate and pressure can also be benefited from
clean perforations.
Accurate acid placement is a major concern in matrix acidizing of carbonates, as the acid
tends to flow preferentially where the permeability is highest, further increasing permeability
and leaving the low- permeability regions of rock untreated.
In some cases, huge increases in water production are observed after a stimulation job
because acid may have preferentially stimulated the high-permeability sections associated
with water.
Once a highly permeable water zone has been stimulated, the chance of acid getting into the
pay zones is reduced and the result is the production of more water. Proper use of diversion
techniques can avoid such disasters.
Computer modeling can determine the best method of placement for
a particular stimulation treatment. Stim CADE well simulation software helps to optimize
matrix stimulation treatments in both production and injection wells. Stim CADE software
(Figure 1) models all aspects of the acidizing process, including the fluid flow for each zone,
reaction kinetics, temperature changes such as cool down, and diversion.

9Matrix Acidizing
Figure 1.1: Stim CADE
Mechanical diversion
Mechanical diversion is achieved by pumping the necessary amount of acid in front of the
intervals to be treated. Coiled tubing has been increasingly used to achieve diversion in the
last two decades. Where the use of coiled tubing is impracticable, other methods of diversion
may be considered. The most common method of mechanical diversion uses ball sealers.
Before injecting the stimulation fluid, balls (made of nylon, hard rubber, biodegradable
materials such as collagen, or combinations of these materials) in the treatment fluid
are used to plug and shut off the perforations that are taking most of the treatment fluid.
Mechanical diversion can also be achieved by using a straddle packer arrangement isolate the
required interval.
Formation Analysis
It is sometimes easy to dissolve plugging solids. The key to success, however, is to dissolve
the plugging solids without damaging the formation. You must know how the formation
minerals will respond to the acid used in the treatment and anticipate how the spent acid will
react as it invades deeply into the formation. Solids dissolved near the wellbore may
precipitate deeper into the formation as they contact other minerals that react with either live
or spent acid.
To maximize matrix acidizing, reservoir quality and formation mineralogy must be analyzed
first.

11Matrix Acidizing
One goal of formation analysis is to control or prevent precipitation of reaction products in
the formation. Several contributions have been made in this area by D.K. Davies. 98-100
Acid treatments for shale , low-permeability formations require more care than treatments for
cleaner, high-permeability zones. More positive methods for zone coverage (e.g., opposed
cup packers, ball sealers, diverting agents) are required to assure uniform acid placement in
nonuniform, layered deposits. Formations with a large amount of fines or clay minerals must
be analyzed to determine the best acid, acid concentration, and appropriate additives for
successful stimulation. Estimates of permeability and wellbore condition help predict
injection rates before and after acid stimulation at injection pressures less than formation
parting pressure. Formation quality is defined by depositional, detrital, and diagenetic
quality.
Figure 1.2: Scanning Electron Microscope photogragh of Significant Clay Minerals
a: kaolinite b: illite c: chlorite d: smectite

11Matrix Acidizing
Quality Control After Pumping.
1. Do not shut the well in after acid injection. Flow the well back to tank or pit as soon as the
flow line is connected.
2. Collect at least three one-quart samples of back-flowed acid for analysis. Sample the acid
backflow at the beginning, middle, and near the end of the flow. If on swab, get a sample
from every other swab run.
Secure a lab analysis for:
a. amount, size and type of solids. b. strength of returned acid.
c. total iron content.
d. presence of emulsions.
e. formation of any precipitates (besides iron).
3. Get the treatment report and pressure charts to the office for evaluation and placement into
the well file.
2.1.3 Fracture acidizing.
Acid fracturing describes the creation of highly conductive fractures by pumping acid at
pressures exceeding the minimum stress in the rock. This method is usually preferred where
the native permeability of the formation is very low.
The proper design of any stimulation treatment should be based on at least a general
understanding of the interactions between the stimulation fluid and the formation.
designs allow producers to reap the most benefits in terms of production, costs, and treatment
success.
Standard fracture acidizing treatments on carbonate formations generally give excellent
results. These are normally performed with the bottomhole treating pressure (BHTP) above
formation fracturing pressure, and rely on fluid pressure to keep the created fracture open.
Acid flows through the open fracture, dissolving or etching the fracture face in such an
uneven manner that flow channels are developed. These flow channels then remain open after
the treating pressure has been reduced and the fracture closes.

12Matrix Acidizing
Acid fracturing of carbonates not only creates long wormholes, but also etches irregular
channels on the fracture face. The irregularity of the etched channels ensures that there is still
communication with the wellbore when pressure is released and the fractures close after the
treatment.
The effective length of the fracture is determined by the length that has been sufficiently
etched and is accessible for flow.
The main factor that adversely affects acid fracture growth and worm-holing is fluid loss.
Acid leak off is not uniform, resulting in the enlargement of some wormholes and natural
fractures. This greatly increases the area from which fluid loss occurs, making fluid-loss
control High
difficult and preventing acid reaching untreated parts of the fracture. One way to control this,
is to pump viscous fluid slugs (pads) intermittently throughout the acid treatment. The initial
pad is used to initiate the fracture and to deposit a filter cake
in it that forms a temporary barrier to prevent acid leak off. With time, acid dissolves and
erodes the filter cake, resulting in increasing leak off. In order to minimize leak off further,
polymer fluid stages are pumped to reestablish control of fluid loss.
Many carbonate formations cannot be successfully fracture acidized at pressures above the
formation fracture pressure using standard fracture acidizing techniques.
The "closed" fracture acidizing technique is designed to allow acid to flow through existing
"closed" fractures below fracturing pressure in a channeling manner.
Wide grooves or channels in the fracture face are then formed as acid is pumped at low rates
and allowed to dissolve large flow channels. These grooves tend to remain open with good
flow capacities under severe closure conditions and also allow fines or emulsions to be more
easily produced.
The response of a well to a fracture acidizing treatment does not depend solely on the acid
penetration distance, but depends also on the conductivity that results from the spending acid.
Prediction of the well response depends on knowing the distribution of that conductivity as it
relates to acid spending.

13Matrix Acidizing
To this end a number of laboratory tests have been developed which try to relate conductivity
to acid spending.
Conventional. In the conventional acidizing treatments at most three stages are pumped: pre-
flush, acid, and over-flush. Pre-flush is used to initiate a fracture and lower the temperature
around the fracture. When plain acid is used, acid reaction is very fast, dissolving large
amounts of rock near the wellbore but creating little penetration distance. Reaction retarding
additives can be added to slow down the acid reaction rate. However, if the reaction is slowed
to the point that the leading edge of the acid volume has considerable remaining acid
strength, long penetration distance is achieved at the expense of not dissolving enough rock.
Thus, an optimum design
must compromise between penetration distance and rock dissolving efficiency. During acid
stages, fracture temperature could be raised considerably due to exothermal reaction.
The function of over-flush is to push the acid volume forward, thereby increasing the
penetration distance and dissolving rock further from the wellbore. For plain acid, a large
over-flush is not needed because it cannot efficiently increase penetration distance. However,
if the acid reaction is retarded, an over-flush can be very effective in increasing penetration
distance.
2.2 Acids used in acidizing stimulation.
2.2.1Mineral acids (HCl and HF)
Most of the failures of matrix stimulation treatments can be imputed to incorrect field
procedures.
Deep consideration has been given to the knowledge of the chemical reactions between the
components of the involved systems, and the various types of formation damage which may
occur. Also close attention has been paid to optimizing the composition of the stimulation
fluids with to the reservoir rock lithology,' by means of proper selection of additives and by
considering the effects of temperature and other important chemical and physical parameters.
Acidizing fluids are the product of research and field experience. Although laboratory tests
contribute to the design of acidizing fluids, field tests and experience determine the final fluid
composition.

14Matrix Acidizing
Once a fluid appears to work, it will be used routinely in a specific field. Routine use,
however, does not ensure good acid quality.
The HCl and HF concentrations in weight percent are determined by titration.
Method of HF Analysis :-
The test kit employs a novel volumetric method for determining fluoride ion concentration
directly. Common volumetric analyses of HF in mud acid are indirect. These techniques
measure the total acidity from both HCl and HF and then subtract the HCl acidity deter-
mined by titration for the chlorides . Therefore, the result obtained for fluoride concentration
depends on the assumption that the chloride content is accounted for entirely by the HCl
added to the treating fluid. Although this is usually a good assumption, excess chlorides
caused by contamination will cause the HF concentration to appear lower than it actually is.
To eliminate the uncertainty introduced by this possibility, we chose a direct method of
analysis.
We developed a method using 0.05 M thorium nitrate [Th(N03)4 '4H20] as a titrating
solution. Although the fluoride-specific ion electrode provides an excellent direct analysis for
fluoride, we decided the simpler volumetric analysis is more appropriate for rapid field
testing. Two Th(N03)4 methods are described in the literature 7,8 In both methods, thorium
tetrafluoride (ThF4) precipitates during the titration; at the endpoint, the excess thorium
complexes with the indicator to cause the yellow-to-purple-red color change. These methods
require strict pH control for accurate analysis. Rowley and Churchill reported that a pH of 2.9
to 3.4 gives results that are stoichiometrically correct, with a pH of 3.0 giving the most
positive endpoint.
The method used in our quality-control survey permits analysis throughout a broader pH
range, further simplifying the titration for rapid use in the field. A mixture of ethanol and
ethylene glycol monobutyl ether (EGMBE) in a sodium-acetate/acetic-acid buffer permits
analysis within a pH range of 2.8 to 4.2. Without the ethanol/EGMBE mixture, the indicator,
alizarin red S, begins its acid-base color change from yellow to red at pH 3.7. Therefore,
without this mixture, at pH values of 3.7 and higher, the endpoint is at least partially obscured
by the initial red-orange color. Also, without this mixture, at a pH of 4.2 the endpoint is

15Matrix Acidizing
premature by about 20 %. The presence of ethanol and EGMBE preserves the initial yellow
at a pH as high as 5.5, permitting a much clearer endpoint. Further, the presence of these
liquids eliminates most of the error caused by premature endpoint. At a pH of 4.2 the
endpoint was 4.4% premature instead of 20%, and at a pH of 3.7 it was just 1.8% premature.
Method of HCl Analysis
The HCl concentrations are determined by titration with sodium hydroxide (NaOH). Again,
as in the HF analysis, 5 mL (5 cm 3 ) o f the diluted acid sample (diluted 1:5) is titrated in I-
mL (I-cm3) increments. The titrating solution is 0.25 N aqueous NaOH that contains the
endpoint indicator methyl red. Because this analysis actually yields a total acid concentration,
including acid present as both HCl and HF, the HCl concentration is determined by
subtracting the HF concentration from the total acid concentration. This subtraction must be
done using molar concentrations rather than weight percent.
In summary, HF and HCl concentrations are determined by the following steps.
1. Titrate diluted acid samples with 0.05 MTh(N03)4 and 0.25 N NaOH separately.
2. determine the uncorrected acid concentrations from fig2.
3. determine the fluid density from Fig. 3.
4. Divide the uncorrected concentration by the density to determine the weight percent of
HCl and HF

16Matrix Acidizing
Figure 3: Chart for Determining Uncorrected Acid Concentrations
Figure 4: Density Correction for HCL and HF Concentration

17Matrix Acidizing
2.2.2 Organic acids.
Carbonate acidizing has been carried out using Hcl-based stimulation fluid for decades.
However, at high temperatures, Hcl does not produce acceptable results because of its fast
reaction, acid penetration, and hence surface dissolution, and its high corrosion rate.
Organic acids are mostly used in high temperature reservoirs, where the fast HCl spending
rate can cause sever tubing corrosion and poorly etched fractures.
Organic acids cannot used at high consternation because of Calcium salts. Thus, the
concentrations of acetic and formic acids used are less than 13 and 9 wt% respectively. This
is. Because the reaction products (e.g. calcium format) can precipitate at higher acid
concentration.
In field treatments, mixtures of organic acids have been used stimulate high
temperature/pressure wells and remove calcium carbonate scale.
The new organic acid is obtained at an initial concentration of 50 wt%. For the experimental
procedure, the acid was diluted to concentration of 10 wt%. Deionized water was obtained
from a water purification system that has a resistivity of 18.2 M ohm.cm and added to the
original acid solution so the final concentration was obtained at 10 wt%. A corrosion
inhibitor (proprietary alkoxylated fatty amine salts, alkoxylated organic acid, thiourea) at 0.1
wt% added to prepare the acid.
2.3 Acidizing stimulation additives.
2.3.1 Corrosion inhibitors.
When pumping stimulation acids through the tubing or casing into the formation we will
experience different corrosion processes. The corrosiveness of an acid mainly depends on its
concentration and temperature. The rate of corrosion is measured by actually weighing a
small specimen of steel before and after exposure to the acid.
A counter measure is the use of corrosion inhibitors which retards the reaction rate of acid on
steel by establishing a film that protects metal from corrosive fluids. In oilfield systems one
class of chemicals is used as corrosion inhibitors: organic amine based.

18Matrix Acidizing
In general, they work by interfering with the production of hydrogen at the cathode region.
The majority of organic inhibitors are organic-film-forming inhibitors. These are organic
chemicals with a polar, water loving, head and a long hydrocarbon, oil loving, tail. When
applied, these compounds align with the polar head towards the metal and the tail towards the
outside, effectively establishing an oil-wet film on the metal surface. This inhibitor film
breaks the corrosion cell by separating the metal surface and the electrolyte containing water
.
2.3.2 Surfactant.
We experience different secondary actions and side effects during and due to acidizing
treatments. Some of them can only be handled by the use of different surface active
agents (surfactants). The emphasis of the surfactants’ impact in oil production lies in the
change of interfacial tension between:
1- Two Liquids (Oil And Water),
2- A Liquid And A Solid Or
3- A Liquid And Gas .
Surface active agents can have a variety of applications depending on the phases at the
interface. Using a surfactant as a demulsifies, the interfacial tension of a liquid-liquid
interface can be reduced in order to break the emulsion which can create severe damage
downhole and eventually reduce the viscosity
2.3.3 Anti sludge agents.
Acid contacted with heavy asphaltic crudes may form insoluble sludge. Sludge generally
consists of asphaltenes and may also contain resins and paraffin waxes, high molecular
weight hydrocarbons and formation fines or clays. Some surfactants which usually also
function as emulsion preventers might keep colloidal material dispersed. High strength acids,
in general, tend to form severe sludges.

19Matrix Acidizing
2.3.4 Suspending agents
Carbonate and sandstone formations may contain HCl-insoluble's such as clays and silts
which after the acidizing treatment can cause blocking in the formation pores or fractures if
the fines released by the acid are allowed to settle and bridge. Suspending agents hold the
fine undissolved clay and silt particles in suspension and thereby play an essential role in the
effectiveness of their removal .
2.3.5 Chelating or sequestering agents.
big concern in production as well as in injection wells are iron scale deposits which may
precipitate from the acidizing treatment. Typical scale deposits are iron carbonate, FeCO ,
iron sulfide, FeS , and iron oxide, Fe O . These precipitates are water-insoluble and do not
only restrict production or Injectivity, they can also influence the performance of an acidizing
job significantly.
Hydrochloric acid, for instance, when injected through the tubing or casing dissolves part of
existing iron scales and carries iron compounds put into solution as iron chloride, FeCl , into
the formation. The iron in solution will undergo hydrolysis and reprecipitate as iron
hydroxide, Fe(OH) . The worst case is when iron hydroxide once more reacts with oxygen
resulting in the formation of Fe(OH) which is much less soluble and hence a very strong
plugging material. Formation of this insoluble plugging material in the near wellbore can
reduce permeability and eventually cause permanent plugging of flow channels resulting in
reduced oil and gas production in producing wells or higher required injection pressure and
reduced injection volume in water-flood wells.
The control of reprecipitation of iron deposits from spent acid solutions can be achieved
using sequestering agents. They act to complex ions of iron and other metallic salts to inhibit
precipitation of iron actions in spent hydrochloric acid. Most sequestrates are organic acids
such as acetic, citric or lactic acid, each one being differently effective in reducing the
activities of iron. The effectiveness of the acid furthermore is influenced by its concentration,
the pH of the system and the external temperature of the system .
Sequestered acid has particular application in treating water injection or disposal wells where
iron compounds are deposited on the formation face. Sequestrates should furthermore be
used if rusty tubing or casing is to be contacted.

21Matrix Acidizing
2.3.6 Reducing agents
Normally hydrofluoric acid reacts so rapidly with the siliceous formations that the acid tends
to become spent before penetrating deeply into the formation.
Consequently, an increase in porosity and permeability can only be achieved in zones very
close to the wellbore. The damaged region, though, can very often reach much deeper into the
formation than conventional hydrofluoric acid systems are able to penetrate.
In sandstone matrix acidizing improved penetration of hydrofluoric acid stimulations can be
achieved retarding hydrofluoric acid by complexing fluoride ions with aluminum chloride,
AlCl. The aluminum ions form aluminum fluoride complexes which retard the formation of
the hydrofluoric acid itself.
Retardation is accomplished by constantly controlling the amount of hydrofluoric
acid actually available for the reaction. As a result the retarded acid system always has some
free HF molecules which react quickly with clay minerals but very slowly with sand grains .
In this manner live acid is still available when the acid solution system is pumped deep into
the formation.
2.3.7 Clay stabilizers
Clays are layered minerals of silicon and aluminum oxides and exist in the majority of
sandstone formations. Some can lead to formation damage, either
damage caused by:
1- clay swelling or
2- clay migration.
As soon as their chemical environment is changed in the formation like in acid treatments,
clay particles may be released when the treating solution dissolves the surrounding material.
The particles become entrained in the moving fluids.
The dispersion and movement of fine clay particles in water sensitive formations eventually
plugs flow channels causing a reduction in permeability.

21Matrix Acidizing
The alteration of equilibrium between clays and formation waters which means change in
salinity causing imbalances in the forces between clays.
Ion exchange between the aqueous system and the formation can cause swelling clays which
reduce permeability. The most common swelling clays are smectites and smectite mixtures.
Clay stabilizers act to decrease the activity of ions in order to prevent ion exchange .
In this manner, they are effectively desensitized to swelling and migration or coated or fused,
rendering them immobile Ammonium chloride, NH Cl, is commonly used as a pre- and post-
flush brine or as a spacer when stimulating with hydrofluoric acid. The ammonium ion acts as
a temporary stabilizer for migrating and swelling clays normally found in sandstone
reservoirs. When performing acid stimulations using hydrofluoric acid the wrong spacer can
cause precipitations. Potassium chloride, KCl, for instance, and hydrofluoric acid will form
potassium fluosilicate precipitates, KSiF . Ammonium chloride as a spacer will not induce
the formation of precipitations.
Fluoboric acid, HBF , also provides clay stabilization through reactions related to borate and
fluoborate ions. The cation exchange capacity is strongly decreased and hence well able clays
are desensitized .

CHAPTER 3: MATRIX ACIDIZING
OF CARBONATE FORMATIONS

Chapter 3: Matrix Acidizing of Carbonate Formation
22Matrix Acidizing
CHAPTER THREE
MATRIX ACIDIZING OF CARBONATE FORMATIONS
3.1 Introduction:
Near wellbore formation damage in carbonate formations from one or a combination of
several damage mechanisms, which have been discussed in the first chapter, such as invasion
of drilling fluid and cement solids, clay swelling and sluphing, fine migration inside the
porous media, wettability alteration and scale deposition around the well bore. This damage
in a short radius around the well bore, which is called skin zone, has a great impact on the
formation productivity or injectivity reduction and create further pressure drop inside the
reservoir in the well bore vicinity region.
The aim of carbonate matrix acidizing is to remove the effect of near wellbore damage by
dissolving the matrix of the rock and bypassing the damage by enlarging and connecting the
pore spaces and creating new conductive channels. These conductive channels, which are
referred as wormholes, penetrate the damaged zone up to few feet around the wellbore and
bypass the permeability impairment. Acids used in carbonate matrix treatments are
hydrochloric acid (HCl) or organic acids such as acetic acid (CH3COOH) or formic acid
(HCOOH). These acids are only able to dissolve carbonate minerals; therefore, acid
stimulation in carbonate rocks (limestone or dolomite) is principally achieved by dissolving
the carbonate minerals in the rock matrix and fines that has been released from the rocks.
Carbonate minerals that exist in carbonate rocks are calcite mineral (CaCO3) in limestone
rock and dolomite mineral (CaMg(CO3)2).
Selection of acid type and concentration is an essential stage in carbonate acidizing
stimulation. Choosing the right concentration of acid should be based on laboratory tests
(core flooding tests) on the formation core samples to investigate that which concentration of
particular acid gives the optimum penetration or wormhole creation. In 1984, McLeod
introduced a guide line for carbonate matrix acid stimulation as shown in table (4.1). 15%
HCl is the most widely used in treatments of carbonate rocks; however, higher
concentrations up to 28% can be used for achieving deeper penetration of the
wormholes in deep near wellbore damage conditions.

23Matrix Acidizing
Situation Weight Concentration
Perforating fluid 5% acetic acid
Damaged perforations 9% formic acid
10% acetic acid
15% HCl
Deep wellbore damage 15% HCl
28% HCl
Emulsified HCl
Table 1: McLeod acid use guidelines (McLeod, 2007, p.289)
Organic acids (acetic acid or formic acid) are normally used in cleaning and opening the
perforations or used as a perforation fluid during the casing perforation operation. In
circumstances, where the use of HCl acid is problematic at high temperature
conditions (above 250 F), organic acids should be used for the matrix treatment instead
of HCl acid. At high temperatures, corrosion of tubing, casing, surface and subsurface
equipment with HCl acid cannot be controlled with corrosion inhibitors or it requires a large
amount of corrosion inhibitors which is not feasible economically. Emulsified HCl acid (acid
emulsified with oil) can also be used for accomplishing deep penetration of the wormholes.
(Kalfayan, 2008, pp.161-165).
Following the injection of the main acid treatment fluid (HCl or organic acid), the well
should be afterflushed with an overflush fluid to displace all the acid into the formation and
clean the tubing from the acids. Usually, water is used as an overflush fluid; however, the use
filtered diesel or crude oil are rarely used in oil well acid treatments. Nitrogen (NO2) also can
be utilized as an overflush fluid in displacing acid particularly in gas wells. The volume of
overflush fluid should be slightly more than the volume of the injection string which is either
coiled tubing, production tubing string or a string of connected drill pipes (Williams, Gidley
and Schechter, 1979, pp. 86-89).

24Matrix Acidizing
4.2 Carbonate rock composition and their reactions with acids:
Dolomite or Dolostone , which is mainly formed from dolomite (CaMg(CO3)2) mineral,
will is formed by transforming of limestone rock in a process called dolomitisation. This
process occurs when high magnesium content water flows into limestone rocks and dissolve
it. Magnesium ions (Mg+2
) partially replace the calcium ions (Ca+2
) and reprecipitate in the
form of dolomite (CaMg(CO3)2). Most of the time, the limestone formation will change into
dolomite formation entirely when the formation is highly permeable. If the limestone
formation is dense and its permeability is dependent on naturally existing fractures, the
dolomitisation process only occurs alongside the fractures where the magnesium-rich water
can flow through and contact the limestone formation rocks. Generally, dolostone is harder
and has less solubility compared to limestone rock; therefore, limestone rock porosity
decrease by increasing the weight of the overlying formations. Dolostone rocks are more
porous and permeable because their crystals are larger than the limestone rock crystals and
this provide large pores, pore throats and high permeability (Hyne, 2012, pp.140-152).
Carbonate rocks may not be pure and siliceous minerals can co-exist with the carbonate
minerals in the rock. These siliceous minerals could be quartz or clay minerals that exist in
sandstone, shale or chert rocks. In the presence of a considerable percentage of siliceous
minerals (less than 50%), the carbonate rock is named as sandy, cherty or shaly carbonate
(dolomite or limestone) rock (Williams, Gidley and Schechter, 1979, P.12). Acids which are
used in carbonate acidizing cannot dissolve siliceous minerals (minerals that contain silicon
in their chemical composition) such as clay minerals (Kaolinite, Illite, Semectite and
Chlorite ), Quartz, Mica and Feldspar. Table (4.2) shows the solubility of carbonate and
siliceous minerals in HCl acid.
Mineral
solubility
HCl HCl - HF
Quartz No Very low

25Matrix Acidizing
Chert No Low to moderate
Feldspars No Low to moderate
Micas No Low to moderate
Kaolinite No High
Illite No High
Semectite No High
Chlorite Low to moderate High
Calcite High High, but CaF2
Precipitation
Dolomite High
Ankerite High High
Siderite High
Table 2: Solubility of Carbonate and Siliceous Minerals in Acids (Allen and Roberts, 1993, p. 7-18)
The percentage of impurities and carbonate minerals in the carbonate rock
should be known which affects the design of the acid volume and acid
penetration depth. (Allen and Roberts, 1993, p.7-19) explains that, the use of
hydrofluoric acid (HF), which is specialized for sandstone acidizing stimulation
and powerful in dissolving siliceous minerals, in carbonate formations should
be shunned because (HF) reacts with carbonate minerals and produce insoluble
reaction products (magnesium fluoride (MgF2) /or calcium fluoride (CaF2))
inside the rock pores which causes the damage of the formation and
permeability impairment rather than stimulation as shown below:
CaCO3 + 2HF CaF2 + carbon dioxide (CO2 ) + water (H2O)
CaMg(CO3)2 + 4HF MgF2 + CaF2 + carbon dioxide (2CO2 ) +
water (2H2O)

26Matrix Acidizing
Reaction of common acids (organic acid or HCl) acid in carbonate matrix acidizing with
carbonate minerals in carbonate rocks results in the production of carbon dioxide (CO2) ,
water (H2O) and slats that are soluble in water and the spent acid such as magnesium chloride
(MgCl2) , calcium chloride (CaCl2), calcium acetate (Ca(CH3CO2)2), magnesium acetate
(Mg(CH3CO2)2), calcium formate (Ca(HCO2)2) and magnesium format (Mg
(HCO2)2) as shown in the following reaction equations:
2 HCl + CaCO3 CaCl2 + CO2 + H2O
4 HCl + CaMg(CO3)2 CaCl2 + MgCl2 + 2CO2 + 2H2O
2 CH3COOH + CaCO3 Ca(CH3CO2)2 + CO2 + H2O
4 CH3COOH + CaMg(CO3)2 Ca(CH3CO2)2 + Mg(CH3CO2)2 + 2 CO2 + H2O
2 HCOOH + CaCO3 Ca(HCO2)2 + CO2 + H2O
HCOOH + CaMg(CO3)2 Ca(HCO2)2 + Mg (HCO2)2 + 2 CO2 + 2 H2O
(Kalfayan, 2008, p.148)
3.3 Acid Dissolving Power:
The concept of dissolving power of acids is introduced by Bert B. Williams in 1979.
Acid dissolving power is the measurement of the amount of carbonate minerals dissolved by
an amount of HCl or organic acids on the basis of volume or mass. Acid dissolving power on
the mass basis is called gravimetric dissolving power whereas the measurement on the
volume basis is called volumetric dissolving power. Gravimetric dissolving power expresses
the mass of carbonate mineral that is dissolved by a mass of the acid and can be calculated
according to equation (4.1).
……………… (4.1)
Where: β : gravimetric dissolving power in (Ibm of mineral/Ibm of acid) ν : the
stoichiometric coefficient of the mineral or the acid in the reaction equation MW : the
molecular weight of the acid or the mineral

27Matrix Acidizing
For instance, form the reaction equations of HCl acid with limestone (CaCO3), the
stoichiometric coefficient of HCl ( HCl) and Calcite ( CaCO3) are (2) and (1) respectively
which means that (2) mole of HCl has reacted with (1) mole of calcite mineral . If the
hydrochloric acid has the concentration of 100% by weight, the gravimetric dissolving power,
by applying equation (4.1), will be:
1.372 Ibm CaCO3/ Ibm HCl
(β 100 ) denotes the gravimetric dissolving power of the acid with 100% concentration on the
weight basis (Hill and Schechter, 2000, pp.16-3,16-4). Molecular weight of the acids and
minerals can be found in tables (3.3) and (3.4).
Table 3: Molecular Weight of Acids Used in Carbonate Matrix Acidizing (Cholet,2000, p.205)
Table 4: Molecular Weight of Minerals of HCL Reaction with Dolomite and Calcite (Williams, Gidley and
Schechter, 1979, p.13)

28Matrix Acidizing
3.4 Estimation of the required acid volume for carbonate matrix acidizing:
(Economides, Hill and Ehlig-Economides, 1994, p.383-404) has presented two models
for estimating the required acid volume for matrix treatment of carbonate formations which
are Daccord’s model and volumetric model.
In Daccord’s model, the acid volume can be calculated by using equation (4.3):
………………….. (4.3)
Where:
: is the volume of acid required per unit thickness of the formation in (m3
/m)
: Wormhole radius (desired acid penetration radius) in (m)
: Fractal dimension, experimentally found to be 1.6
: Formation porosity
: Molecular diffusion coefficient in (m2
/sec)
: Acid injection rate per unit thickness of the formation in (m3
/sec/m)
: Constant, experimentally found to be 1.5 10-5
in SI units
: Acid capacity number (dimensionless).
Equation (4.3) can be rearranged to calculate the radius of the wormhole when estimating
for a given acid volume as:

29Matrix Acidizing
………………………… (4.4)
Daccord’s model is based on experiments on dissolution of plaster by water
and the delivery of the acid to the surface of the pores in the rocks is based on
diffusion mechanism without considering acid losses during flooding;
moreover, in the experiments, water and plaster are used which is not exactly
simulate the wormhole propagation phenomena in real situation by acid-rock
reaction. Due to these reasons, acid volume and wormhole radius that have been
calculated by Daccord’s model is different form real situation in oil fields.
Acid capacity number is defined as the rate of the quantity of dissolved
mineral (carbonate mineral) in the acid, that occupy a unit volume of the
reservoir rock pore void, to the quantity of the carbonate mineral that exists in a
unit volume of the reservoir rock as expressed in equation (4.5).
…………….. (4.5)
Where:
: Acid capacity number, dimensionless
: Gravimetric dissolving power of the acid with 100% concentration by
weight
: Desired concentration of the acid on weight basis

31Matrix Acidizing
: Density of the acid in (Ibm/ft3
)
: Initial volume fraction of carbonate mineral in the rock (limestone or
dolomite) : carbonate rock density Ibm/ft3
Volumetric model is based on the assumption of that in carbonate matrix acidizing, a
constant fraction of the carbonate rock will be dissolved by the acid. Laboratory tests on core
samples should be carried out to attain this fraction. The dissolved fraction of the reservoir
rock in the entire formation will be the same as the dissolved fraction in the core samples.
Equation (3.6), which is and empirical equation, is used in volumetric model for
calculating the required acid volume:
……………………. (3.6)
Where:
: The required acid volume per unit thickness of the formation in (ft3
/ft) or (m3
/m)
: Fraction of the rock that dissolved by the acid
: Penetrated radius by the wormholes in (ft) or (m)
: Wellbore radius in (ft) or (m)
: Acid capacity number, dimensionless

31Matrix Acidizing
The fraction of the rock ( which is dissolved by the acid in the core sample can also be
determined by using equation (3.7) :
……………….. (3.7)
( ) is the number of pore volumes that has been filled or injected with acid when the
wormholes breakthrough at the core sample end. The ( ) can be found in laboratory
experiments on the core samples by using neutron radiography which film the enlarged pores
and created wormholes in the cores. Field experiences show that estimated acid volume by
volumetric model is more acceptable and quite close to reality compared to the Daccord’s
model.
3.5 Optimization of the acid injection pressure and rate:
Acid injection pressure in matrix acidizing is limited by the formation fracture pressure.
The injection pressure should be kept below the fracture pressure; therefore, determination of
formation fracture pressure is essential prior to the initiation of the stimulation process.
(Miam, 1992, p.501) explained the procedure of acid injection pressure and rate as:
3.5.1 Determination of the formation fracture gradient:
The formation fracture gradient can be determined from one of these methods:
 Using recorded data from previous formation fracture stimulation treatments in the field
or area.
 Performing leak off or formation parting pressure test to determine the formation fracture
gradient. The test in usually performed by injecting a fluid (water or oil) in to the well
with pumps with low injection rates at the beginning (1/2 to 1/4 barrels per minute). Then
by increasing the injection rate gradually, the surface injection pressure increases. At the
time when the pressure gauge indicator starts to return which indicated the breakage limit
of the formation, the pressure at this point should be recorded and injection should be

32Matrix Acidizing
stopped. The recorded surface injection pressure with the hydrostatic head of the injected
fluid are used to estimate the formation breakage or fracture gradient:
Fracture pressure gradient is not stable and will change as the reservoir pressure changes in
a direct relationship. For new formation or reservoir pressures, the fracture gradient can be
recalculated by using equation (4.9).
……………….. (3.9)
Where:
: fracture pressure gradient (psi/ft)
: Constant (0.33 to 0.5)
: overburden pressure gradient
: Reservoir pressure (psi)
: Depth of the formation (ft)
The constant ( ) can be calculated by using previous or recorded reservoir pressure and
fracture gradient in equation (3.9). For formation depths more than 10000 ft, is 1.0 to 1.2
psi/ft and for depths less than 10000 ft, it is equal to 1.0 psi/ft. the new ( ) can be found for
the new reservoir pressure (PR) by using the same equation (Williams, Gidley and Schechter,
1979, pp.55).
3.5.2 Acid injection rate:
Maximum allowable acid injection rate without creating fracture in the formation can be
found with equation (3.10). It is recommended to keep the acid injection rate at 10% lower

33Matrix Acidizing
than the maximum allowable injection rate as a safety margin to avoid breaking the
formation.
…………………. (3.10)
Where:
: Maximum allowable acid injection rate (bbl/min)
: Average formation permeability (md)
: Formation thickness (ft)
: Formation fracture gradient (psi/ft)
: Formation depth (ft)
: Reservoir pressure (psi)
: Acid viscosity (cp)
: Reservoir drainage radius (ft)
: Wellbore radius (ft)
4.5.3 Maximum allowable surface injection pressure:
Acid injection pressure should not exceed the maximum allowable limit, which can be found
by using equation (3.11), to avoid the breakage of the formation:
……………………… (3.11)
Where:
: Maximum allowable acid injection pressure at surface (psi)
: Formation fructure gradient (psi/ft)
: Density of the acid (ppg)
: Formation depth (ft.)
3.6 Using coiled tubing technology for acid placement and diversion in
matrix acidizing of Arab-D formation (Ghawar oil field – Saudi Arabia)
water injection wells:
(Ginest et al., 1993) have explained the use of coiled tubing technology in matrix acid
treatment operations in Ghawar oil field. Water injection wells in Arab-D formation are open

34Matrix Acidizing
hole completed in intervals ranged between 150 to 250 ft. limestone rocks with permeability
up to 2 Darcy. During drilling and workover operations, the competed interval has been
damaged by the invasion of solids from drilling and workover fluids into the near wellbore
formation pore. This resulted in permeability impairment and injectivity reduction in few
inches around the wellbore.in 1991, 35 acid stimulation jobs is carried out in these wells by
Saudi Aramco Company. HCl acid is used to stimulate the near wellbore matrix in order to
remove the effect of the damage and crate wormholes to bypass the damage. The main
purpose of the stimulation jobs was to increase the injectivity (water injection rate) in the
competed intervals to keep the reservoir pressure above the bubble point and stabilize or
increase the oil production rate and maximize recovery.
In the stimulation jobs diversion of the treating acid was necessary to achieve uniform
stimulation in the whole intervals because:
Severity of the damage was not uniform Permeability of the rocks is different in different
intervals. The completed zone contains short and highly permeable intervals with (1-2)
Darcy; on the other hand, it contains long intervals (several feet) wich have low permeability
(injectivity). These long intervals are significantly contributed to the total injection rate in the
well.
In the stimulation jobs, coiled tubing has been used in acid placement in seven wells. In tow
Stimulate the entire zone uniformly by diverting the acid the acid with foam diverter or
exposing the entire completed zone (the open hole section) to the acid with the aid of jetting
nozzles.
3.6.1 Job evaluation:
Flow meter profiles and injection rate and pressure data were acquired during water injection
operations before and after the stimulation process to evaluate the injectivity improvement
and investigate the uniformity of the stimulation in the entire zone rather than the high
permeability intervals only. Downhole flowmeter tool, which is normally used in through
tubing production logging alongside other pressure and temperature sensor tools, is used to
measure and record the injection rate of the water into the formation at any depth. The
recorded date versus depth is called injection flowmeter profiles.
The injection flowmeter profile measurements were not carried out for the injected acid but
uniform flux of the injected water after the treatment throughout the entire zone indicates the

35Matrix Acidizing
degree of success in uniform stimulation by the acid. Increasing the overall water injection
rate, while decreasing the surface injection pressure, indicates successful diversion of the acid
to the long and low permeability intervals which have a great impact on the increase of the
overall water injection rate with less or almost the same injection pressure after the treatment.
3.6.2 Coiled tubing with foam diversion:
In the Arab-D formation, five water wells were treated with 50 gallon of HCl acid (15%
concentration by weight) and additives per each foot of the open whole zone. The treatment
acid was placed with coiled tubing (1.5 inches outside diameter) and foam was used as
diverter during the treatment in alternate stages with the injected acid. The foam invades high
permeability intervals and diverts the subsequent acid stage to highly damaged and low
permeability intervals. The foam was made from nitrogen, water and surfactants with the
quality of 65-70% nitrogen content. In foam diversion technique, additional surfactant should
be injected to increase its concentration inside high permeability interval pores to improve the
stability of the injected foam. Water injection pressure, injection rate and injection flowmeter
profiles prior to and after the treatment for the five wells show optimistic results to an
acceptable extent. After the treatments, water injection pressure is reduced while the overall
injection rate is increased. This is due to the fact that, the foam has diverted the acid to the
low permeability sections and this caused their stimulation; however, foam stability cannot
last very long and breaks after approximately one hour. Hence, the diversion could not stop
stimulating the high permeability intervals form being stimulated alongside the other
intervals and even some intervals of low permeability are still left untreated. The water
injection flow rate in high permeability intervals is still higher than the low permeability
intervals.
For example, in well (H) among the five wells, increase in water injection rate and
decrease in injection pressure indicates stimulation of some of low permeability intervals.
Figure (4.1) explains that, flow rate of water after the treatment (the dashed line in the figure)
in to low permeability intervals (7018 to 7040 ft.) and (7066 to 7120 ft.) has increased which
means that the acid has been diverted to these intervals and stimulated them. On the other
hand, the interval (7152 to 7204 ft) has remained untreated and water injection rate has not
increased in this section; moreover, some high permeability intervals, such as (7009 to 7018
ft) have been stimulated. Table (4.7) shows the changes in water injection rate and pressure
before and after the treatment for the five wells.

36Matrix Acidizing
Water injection rate (the dashed line in the flowmeter profile) in high permeability
intervals has decreased due to the increase in water flow into the stimulated intervals. For
instance, in the intervals (6981 to 7008 ft.), water injection rate has decreased form approx.
625 RBFPD/ft. to 375 RBFPD/ft. The reason for non-uniform stimulation of the intervals is
that the stability of the foam cannot last for long time in long intervals and this affect the
diversion efficiency. In coiled tubing acid placement, the coiled tubing/borehole annulus is
usually filled with acid which allow the acid to be in contact with the entire zone at
bottomhole temperature condition. This reduces the degree of diversion effectiveness.
Figure 5: Water Injection Profile After Matrix Acidizing for Well (H) in Arab-D
Formation (Ginest et al., 1993)

37Matrix Acidizing
Table 5: Water Injection Rate and Pressure Changes, in Arab-D Formation Water
Injection Wells, After Matrix Acid Treatment with Using Foam Diverter (Ginest et al.,
1993)
3.6.3 Coiled tubing acid placement with rotating side jetting nozzles:
When using jetting nozzles as a bottomhole coiled tubing assembly (attached to the end of the
coiled tubing), there is no need for chemical diverter and this decrease the cost of the
stimulation job. In Arab-D formation water wells, coiled tubing with side jetting nozzles was
used to place the stimulation acid (having 15% concentration by weight) at rate of 50 gallon
per each feet of the openhole zone. Acid-carbonate rock reaction rate at high bottomhole
temperature is very high and any contact between them can result in significant stimulation or
wormhole creation. Thus, the jetting nozzles can increase the contact by jetting the acid
directly toward the formation walls or rocks.
of these wells the acid has been diverted with jetting nozzles and in the other five wells, the
diversion has been accomplished by using foam.
The used of coiled tubing can be considered as successful choice in the stimulation jobs due
to these positive points:
Less time consuming in comparison to bull heading technique.
Availability of space (the wells are onshore)
Allows cleaning the wellbore from drilling fluid and cuttings, by circulating them through
tubing/ coiled tubing annulus, rather than carrying them into the porous media with the
treatment acid

Chapter 4: Conclusion and Recommendation
39Matrix Acidizing
Chapter 4: Conclusion and
Recommendation

41Matrix Acidizing
Conclusion
The project concluded by
 Introducing specified matrix acidizing and others, and showing the most
common one in the petroleum industry.
 After reviewing other researchers works, all types of matrix acidizing were
describing and the advantages and disadvantages was defined. finally, how the
formation acidized by deferent ways has been discussed.
 Finally, the result shows that by matrix acidizing in carbonate reservoir, the
production rate can be increased based on the optimized acid used, such as:
 Organic acids M
 ineral acids (hydrochloric and hydrofluoric acids)
 The production rate can be increased also by using additives, such as
 corrosion inhibitors
 surfactant
 anti sludge agents
 chelating or subsequent additives
 reducing agents
 clay stabilizer

41Matrix Acidizing
Recommendation
 Matrix acidizing process is a very sensitive process, should apply in accurate way
to prevent problems such as; corrosions and plugs.
 Some of acids have a high dissolving power so its very important to adjust the
concentration and the volume of the acids used to prevent high formation
acidizing.
 Matrix acidizing deals with some poisons acids so it’s important to prevent sever
injuries.
 In this project, we discussed matrix acidizing in carbonate reservoir so we hope in
future other researchers search for matrix acidizing in sandstone reservoir.

42Matrix Acidizing
References
Huang, T., Ostensen, L., & Hill, A. D. (2000, January 1). Carbonate Matrix Acidizing
with Acetic Acid. Society of Petroleum Engineers. doi:10.2118/58715-MS
McLeod, H. O. (1984, December 1). Matrix Acidizing. Society of Petroleum
Engineers. doi:10.2118/13752-PA
Rike, J. L. (1971, November 1). Workover and Completion Technology - A Survey.
Society of Petroleum Engineers. doi:10.2118/3715-PA
Curtis, J., & Kalfayan, L. (2003, January 1). Improving Wellbore And Formation
Cleaning Efficiencies With Environmental Solvents And Pickling Solutions. Society
of Petroleum Engineers. doi:10.2118/81138-MS
Milligan, M. (1994, January 1). Well Stimulation Using Acids. Petroleum Society of
Canada. doi:10.2118/94-01-01
Hall, J. A. (2005, January 1). Designing The Perfect Drilling Fluid Additive: Can It
Be Done? Society of Petroleum Engineers. doi:10.2118/95196-MS
Bartko, K. M., Chang, F. F., Behrmann, L. A., & Walton, I. C. (2007, January 1).
Effective Matrix Acidizing in Carbonate Reservoir - Does Perforating Matter? Society
of Petroleum Engineers. doi:10.2118/105022-MS
McLeod, H. O. (1984, December 1). Matrix Acidizing. Society of Petroleum
Engineers. doi:10.2118/13752-PA
King, G. E. (1986, May 1). Acidizing Concepts - Matrix vs. Fracture Acidizing.
Society of Petroleum Engineers. doi:10.2118/15279-PA
Allen , T. O. and Roberts, A. P. (1993) Production Operations : Well completions,
workover, and stimulation. 4th edn. Tulsa, Oklahoma, USA: Oil & Gas Consultants
International
Cholet, H. (ed.) (2000) Well Production Practical Handbook. Paris, France: Technip
Economides, M. J., Hill, D. A., and Ehlig-Economides, C. (1994) Petroleum
Production Systems. Upper saddle river, NJ: Prentice Hall
Ginest, N.H., Phillips, J.E., Al-Gamber, A.W.A. and Wright, D.W. (1993) ‘Field
Evaluation of Acid Simulation Diverter Materials and Placement Methods in Arab-D
Injection Wells With Openhole Completions’ SPE Production Operations
Symposium.
Oklahoma City, Oklahoma, 21-23 March. Richardson, TX, USA: Society of
Petroleum
Engineers, pp.105-114.
Hill, A. D. and Schechter, R. S. (2000) ‘Fundamentals of Acid Stimulation’, in
Economides, M. J. and Nolte, K. G. (eds.) Reservoir Stimulation. 3rd edn. Chichester,
West Sussex, England, UK: John Wiley & Sons. pp. 16-3 to 16-4.
Hyne, N. J. (2012) Nontechnical Guide to Petroleum Geology, Exploration, Drilling
&
Production. 3nd edn. Tulsa, Oklahoma: PennWell Corporation

43Matrix Acidizing
Kalfayan, L. (2008) Production Enhancement with Acid Stimulation. 2nd edn. Tulsa,
Oklahoma: PennWell Corporation.
McLeod, H. Q. (2007) ‘Matrix Acidizing’, in Lake, L. W. and Clegg, J. D. (eds.)
Petroleum Engineering Handbook: Production Operations Engineering. Richardson,
TX, USA: Society of Petroleum Engineers, pp.275-321.
Miam, M. A. (1992) Petroleum engineering handbook for the practicing engineer.
Tulsa, Oklahoma: Penn Well Books.
Williams, B. B., Gidley, J. L. and Schechter, R. S. (1979) Acidizing Fundamentals.
Dallas, TX, USA: Society of petroleum engineers of AIME.

matrix acidizing in carbonate reservoir

More Related Content

What's hot

Similar to matrix acidizing in carbonate reservoir

Recently uploaded

matrix acidizing in carbonate reservoir