1.
SUEZ CANAL UNIVERSITY.
FACULTY OF PET & MIN ENGINEERING.
PETROLEUM DEPARTMENT

2.
COMPUTER APPLICATIONS.
ACIDIZING
PROF.DR:
AHMED GAWISH

3.
WORKING TEAM
• Hossam Hamdy Abd Eltwab SEC 2
• Mohamed Adel Elsemary SEC 3
• Ahmed Gamal Ahmed Mohamed SEC 1
• Kareem Hassan Ahmed Elfarash SEC 3

4.
Contents
•1-Overview of Acidizing
•2-Types of Acidizing
•3-Acid additives
•4-Case study

5.
Well Stimulation
• Sometime, petroleum exists in a formation but is unable to
flow readily into the well because the formation has very low
permeability.
 Natural low permeability formation.
 Formation damage around the wellbore.
• Well Stimulation overcomes low permeability by creating new
flow channels or enlarging old ones.
• Wells are stimulated immediately after completion or whenever
production drops during the life of the well.

6.
Formation damage can occur during any well
operation including :
1-Drilling
2-Cementing
3-Perforartions
4-Production
5-Workover

7.
Three ways for Stimulation
• The oldest method is to use Explosives.
• During 1930’s, acid stimulation, became
economically viable.
• Hydraulic Fracturing, the third stimulation method,
was introduced in 1948.

8.
Acid Stimulation
• If the formation is composed of rocks that dissolve upon
being contacted by acid then a technique known as
acidizing may be required.
• Reservoir Rocks most commonly acidized are
carbonate reservoirs (Limestone and Dolomite).
• Acids that are strong enough to dissolve rock are
often strong enough to eat away the metal of the
pipes and equipment in the well. Therefore, Acidizing
involves a compromise between acid strength and
additives to prevent damage of equipment.

9.
• Acidizing operation basically consists of pumping from fifty
to thousands of gallons of acid down the well.
• The acid travels down the tubing, enters the perforations,
and contacts the formation.
• A hydrochloric acid (HCl) solution is generally the most
efficient and economic agent for acidizing carbonate
formations. It will dissolve Calcium Carbonate (CaCO3),
Dolomite (CaMgCo3), Siderite (FeCO3), and Iron Oxide
(Fe2O3). HCl is a strong and hazardous acid, highly
corrosive to iron and steel.

10.
• If the formation is extremely hot, above 250F or when
formation conditions make a weaker, less-corrosive acid
more desirable, the acidizing contractor frequently uses a
solution of acetic acid and formic acid.
• Other acids that are sometimes used include sulfanic, nitric,
and hydrofluoric acids. The last two are costly and very
dangerous.
• Acids are diluted in water. The concentration ranges from 3
to 28% acid by weight, depending on the type of acid and
factors such as reaction time, corrosion hazard, and
emulsion-forming properties of the crude oil.

11.
• The acid type and acid concentration in acid solution used in
acidizing is selected on the basis of minerals in the formation and
field experience.
• For sandstones, the typical treatments usually consist of a
mixture of 3 wt% HF and 12 wt% HCl, preceded by a 15 wt% HCl
pre-flush.
• For carbonate matrix acidizing Weak acids are suggested for
perforating fluid and perforation cleanup, and strong acids are
recommended for other treatments.

12.
• McLeod (1984) presented a guideline to the selection of acid on the
basis of extensive field experience. His recommendations for
sandstone and carbonate reservoirs treatment are shown in Tables
below

13.
Acidizing types
•There are three basic acidizing treatments:
a) Acid Fracturing
b) Matrix Acidizing
c) Spotting
•The methods for both acid fracturing and matrix
acidizing are the same, except for the amount of
pressure applied.

14.
1-Matrix Acidizing
• Matrix acidizing ( also called acid matrix treatment) is a technique
to stimulate wells for improving well inflow performance. In the
treatment, acid solution is injected into the formation to dissolve
some of the minerals to recover permeability of sandstones
(removing skin) or increase permeability of carbonates near the
wellbore.
• In Matrix Acidizing the acid injection pressure is below formation
fracture pressure
• During matrix acidizing the acids dissolve the sediments and mud
solids within the pores that are inhibiting the permeability of the
rock.

15.
• mostly used in sandstone formations.
• Due to the extremely large surface area contacted
by acid in a matrix treatment, spending time is very
short. Therefore, it is difficult to affect formation
more than a few feet from the wellbore.

16.
2-Acid fracturing
• The acid injection pressure is above the formation fracture pressure
. the reservoir is hydraulically fractured and then the fracture faces
are etched with acid to provide linear flow channels to wellbore
• the application of acid fracturing is confined to carbonate reservoirs
and shouldn’t be used to stimulate sandstone, shale, or coal-seam
reservoirs.
• It is a popular method because even injecting acid at a moderate
pumping rate in low permeability limestone and dolomite formations
usually results in fracturing.

17.
• A major problem in fracture acidizing of carbonate formations
is that acids tend to react too fast with carbonates and are
spent near the wellbore so we must retard acid reaction rate .

18.
Retardation of acid
To achieve deeper penetration in fracture
acidizing, it is often desirable to retard Acid
reaction rate. This can be done by
• Gelling
• Emulsifying
• Chemically retarding the acid

19.
a-Gelled Acid
• The use of gelled acid for fracture acidizing has increased to
the point that it is now the most used technique.
• The introduction of more temperature-stable gelling agents
with ready application up to temperatures of about 400°F
has been a major factor in selecting gelled acid for acid
fracturing. Two types of gelling systems, polymers and
surfactants, are in common use.

20.
b-Emulsified Acid
• For many years the primary retarded acid for fracture acidizing
was an acid-in-oil emulsion. This type retarded acid is very
functional but is no longer the primary fracture acid method used.
• It has limited temperature range and stability, with high viscosity
and high friction loss.
• It does, however, have the ability to restrict contact between the
acid and formation, to reduce fluid loss, and to retain large
quantities of the treating fluid in the fracture.

21.
c-Chemically-Retarded acid
• Acid-Retardation of HCl is obtained by the addition of unique
surfactants to the acid which form protective films on the
surface of limestone or dolomite.
• These films retard reaction rate in much the same way that
an acid corrosion inhibitor protects metal.
• In addition to retarding acid reaction rate, chemical retarders
tend to promote non-uniform etching of fracture faces, thus
increasing fracture conductivity.

22.
3-Spotting
• Spotting acid means to pump a small amount of acid into a
particular spot in a well.
• Spotting removes deposits on the face of the producing
formation. A rig operator may also spot a well to free stuck drill
pipe or to dissolve junk in the hole. This works by corroding
the metal.

23.
Acid Additives
• Acidizing can cause a number of well problems. Acid may :
(1) release fines
(2) create precipitants
(3) form emulsions
(4) create sludge
(5) corrode steel
• Additives are available to correct these and a number of other
problems

24.
• Surfactants : should be used on all acid jobs to reduce
surface and interfacial tension, to prevent emulsions, to water-
wet the formation, and to safeguard against other associated
problems.
• Suspending Agents: Most carbonate formations contain
insolubles which can block formation pores or fractures if fines
released by acid are allowed to settle and bridge.
• A suspending surfactant, such as Halliburton's HC-2, in
concentrations of about five gallons per 1,000 gallons of acid
may suspend fines for more than 24 hours, and possibly as
long as seven days. Suspending agents are usually polymers
or surfactants .

25.
Anti-sludge agents
• Some crudes, particularly heavy asphaltic crudes, form an insoluble sludge
when contacted with acid, with greater problems experiences with high
strength acid. Dissolved Fe(III) in acid appreciably increases the possibility
of sludge. The primary ingredients of a sludge are usually asphaltenes.
• Sludges may also contain paraffin waxes, high-molecular weight
hydrocarbons, formation fines, clays, and other materials.
• The addition of certain surfactants can prevent the formation of sludge by
keeping colloidal material dispersed. These sludge-preventing surfactants
usually prevent an emulsion

26.
Corrosion inhibitors
• They are chemical additives that reduce the rate of corrosion of steel by
acid.
• There are two primary reasons for using corrosion inhibitors:
(1) to protect the acid pumping and handling equipment
(2) to protect well equipment.

27.
Factors that govern the degree of acid attack on
steel are:
1) type of steel including hardness
2) temperature
3) type of acid
4) acid concentration
5) acid contact time

28.
Acidizing Method
• After crew members pump in the acid under low, high, or no pressure,
they seal the well to allow the acid to react with the rock.
• The length of this shut-in time depends on how long it takes for the acid
and rock to react, or the reaction time. Reaction time may be zero for
HCL in a limestone formation because the acid is spent by the time it is
placed. Other acids and formations may require a few hours to acidize.
• Finally, the crew pumps in a fluid to displace the spent acid and disposes
of it.

29.
Factors controlling the reaction rate of acid
are:
1- area of contact per unit volume of acid
2- formation temperature
3- pressure
4- acid concentration
5- acid type
6- physical and chemical properties of formation rock
7- flow velocity of acid

30.
Case Study 1
Calculation of acid volume required
Dissolving power of Acids :
• The dissolving power on a mass basis is called gravimetric dissolving power and is
defined as :
β = Ca
vm MWm
vaMWa

31.
• The dissolving power on a volume basis is called volumetric dissolving power
and is defined as
X = β
ρa
ρm
Where :
X = volumetric dissolving power of acid solution, ft3
mineral / ft3
solution
ρa = density of acid, lbm/ft3
ρm = density of mineral, lbm/ft3

32.
Acid volume requirement
• The acid volume should be high enough to remove near wellbore formation damage and
low enough to reduce cost of treatment.
• The acid preflush volume is usually determined on the basis of void volume calculations.
The required minimum acid volume is expressed as
𝑉𝑎 =
𝑉 𝑚
𝑋
+ 𝑉𝑝 + 𝑉𝑚
𝑉𝑚 = 𝜋 𝑟𝑎
2 − 𝑟𝑤
2 1 − ∅ 𝐶 𝑚
𝑉𝑝 = 𝜋 𝑟𝑎
2 − 𝑟𝑤
2 ∅
Where :
𝑉𝑎 = the required minimum acid volume, ft3
𝑉𝑚 = volume of minerals to be removed, ft3
𝑉𝑝 = initial pore volume, ft3
𝑟𝑎 = radius of acid treatment, ft
𝑟𝑤 = radius of wellbore, ft
∅ = porosity, fraction
𝐶 𝑚 = mineral content, volume fraction.

33.
Example :
A sandstone with a porosity of 0.2 containing 10 v% calcite (CaCO3) is to be
acidized with HF/HCl mixture solution. A preflush of 15 wt% HCl solution is to
be injected ahead of the mixture to dissolve the carbonate minerals and
establish a low pH environment . If the HCl preflush is to remove all
carbonates in a region within 1 ft beyond a 0.328-ft radius wellbore before the
HF/HCl stage enters the formation, what minimum preflush volume is required
in terms of gallon per foot of pay zone?
(given : density of CaCO3 = 169 lbm/ft3 , Specific gravity of acid solution = 1.07 )

34.
Case Study 2
Acid injection rate and injection pressure
• Acid injection rate :
The maximum injection rate limited by the breakdown pressure is expressed as
𝑞𝑙,𝑚𝑎𝑥 =
4.917×10−6 𝑘ℎ ( 𝑝 𝑝𝑑−𝑝 𝑅−∆𝑝 𝑠𝑓 )
𝜇 𝑎 ( ln
.472𝑟 𝑒
𝑟 𝑤
+𝑆 )
𝑝 𝑏𝑑 = 𝐺𝑓 × 𝐿
Where
• 𝑞𝑙,𝑚𝑎𝑥 = maximum injection rate, bbl/min
• k = permeability of undamaged formation, md
• h = thickness of pay zone to be treated, ft
• 𝑝 𝑏𝑑 = formation breakdown pressure, psia
• 𝑝 𝑅 = reservoir pressure, psia
• ∆𝑝𝑠𝑓 = safety margin, 200 to 500 psi
• 𝜇 𝑎 = viscosity of acid solution, cp
• 𝑟𝑒 = drainage radius, ft
• 𝑟𝑤 = wellbore radius, ft
• S = skin factor, ft.
• 𝐺𝑓 = formation fracture gradient , psi/ft
• L = Total depth , ft

35.
• Acid injection pressure
The surface injection pressure is related to the bottom-hole
flowing pressure by :
𝑝𝑠𝑖 = 𝑝 𝑤𝑓 − ∆𝑝ℎ + ∆𝑝 𝑓
∆𝑝ℎ= .433 𝛾 𝐿
∆𝑝 𝑓 =
518 𝛾0.79 𝑞1.79 𝜇0.207
1,000 𝐷4.79 𝐿
𝑝 𝑤𝑓 = 𝑝 𝑏𝑑 − ∆𝑝𝑠𝑓
Where
• 𝑝𝑠𝑖 = surface injection pressure, psia
• 𝑝 𝑤𝑓 = flowing bottom-hole pressure, psia
• ∆𝑝ℎ = hydrostatic pressure drop, psia
• ∆𝑝 𝑓 = frictional pressure drop, psia.
• 𝛾 = Specific gravity of acid
• q = injection rate, bbl/min
• 𝜇 = fluid viscosity, cp
• D = tubing diameter, in.
• L = Total depth , ft.

36.
Example :
A 60-ft thick, 50-md sandstone pay zone at a depth of 9,500 ft is
to be acidized with an acid solution having a specific gravity of
1.07 and a viscosity of 1.5 cp down a 2-in. inside diameter (ID)
coil tubing. The formation fracture gradient is 0.7 psi/ft. The
wellbore radius is 0.328 ft. Assuming a reservoir pressure of
4,000 psia, drainage area radius of 1,000 ft, and a skin factor of
15, calculate
(a) the maximum acid injection rate using safety margin
300 psi.
(b) the maximum expected surface injection pressure at
the maximum injection rate.

37.
Reference :
• Petroleum Production Engineering, A Computer-Assisted Approach
• Petroleum reservoir engineering practice