2. Review
• Well stimulation is a technique used to improve the flow of oil or
gas from the reservoir by dissolving the rock or creating new
channels around the wellbore.
below fracture pressure.
above fracture pressure.
Review
2
Matrix
Acidizing
Fracturing
Acidizing
3. • Formation Damage:
An area of decreased permeability around the wellbore, It is often called
skin damage.
• Some source of formation damage
*A Successful Stimulation
treatment
Review
3
Drilling Fluid
•Weighting Agents (Barite)
•Fluid Loss Additives (CaCo3)
Formation Clay
•Swelling (Semitic)
•Disintegration (Illite)
•Mobile (Kaolinite)
Fluid
Incompatibilities
•Precipitates
•Change the formation wettability
•Emulsion
•Clay sewlling
Skin Factor
Reduced
Effective Wellbore
Radius Increased
Drawdown
4. • The most common Acids
which used in acidizing
operation included :
Review
4
MineralAcids
Hydrochloric Acid
HCL
Hydrofluoric Acid
HF
Phosphoric Acid
H3PO4
Nitric Acid
NHO3
OrganicAcids
Acetic Acid
CH3COOH
Formic Acid
HCOOH
6. • Al-Harthy
(2008/2009)
(A) Grains of quartz cemented by overgrowth of carbonates
(B) Quartz
(C) Feldspar
(D) Porosity reduction occurs from pore-filling clays such as kaolinite
(E) Pore-lining clays such as illite
SandstoneConstituents
6
7. • Sandstone Formation
• Matrix acidizing mostly used in sandstone formations.
• Are mostly formed by quartz , Also have some carbonate particle
• Usually use HF as a quartz solvent
Highly Toxic, Highly Corrosive, Toxic and Corrosive vapors
* SiO2(Silica, Quartz) will not react wit Hydrochloric HCL acid
• It is difficult to affect formation
more than a few feet from the wellbore.
SandstoneFormation
7
6HF + SiO2 H2SiF6 + 2H2O
Mud Acid =
HF + HCL
8. Sandstone Acidizing Mechanism
HF + Mineral + HCL → ALFX + H2SiF6
H2SiF6 + Mineral + HCL → Silica Gel + ALFX
ALFX + Minerals → AlFY + Silica Gel ; X>Y
• When sandstone formation is treated with mud acid: (Mahmoud et al. 2011)
• Formation of potassium and sodium silicate precipitates
• Formation of calcium fluoride precipitates
• Formation of hydrated silica precipitates
AcidizingMechanism
8
9. Hydrochloric Acid Chemistry System
• The use of HCl alone causes significant damage.
• Weak organic acid reduces the damage.
• Zeolite minerals are sensitive to
HCl and strong mineral acids.
• All fluids that are injected should have
an organic Acid included to maintain a
low-pH environment.
* An HCl preflush is always injected in sandstones prior to the HF
Treatingfluids
9
The Zeolite Family
Mineral Description
Heulandite Dissolve in contact with HCL
Occur in shallow environment
No gelatin formed
Chabazite Dissolve in contact with HCL
Occur in medium-depth environment
No gelatin formed
Natrolite Dissolve in contact with HCL
Occur in deeper environment
gelatin formed
Analcime Dissolve in contact with HCL
Occur in deeper environment
gelatin formed
10. Chemistry of Hydrofluoric Acid Systems
• HF is the only common, inexpensive mineral acid able to dissolve
siliceous minerals.
• For any acid system to be capable of damage removal, it should
contain HF in some form.
• The most common formulation :
1- Ammonium bifluoride NH4HF2
It attacks silica component:
2- By diluting concentrated HCl-HF formulations.
Treatingfluids
10
SiO2 + 4 [NH4][HF2] → SiF4 + 4 NH4F + 2 H2O
11. • Numerous mineral species react with HF, and they generate aluminum silica
fluoride complexes.
(Smith et al., 1965).
.
Treatingfluids
11
Chemical composition of typical sandstone minerals
Classification Mineral Chemical Composition
Quartz SiO2
Feldspar
Microcline
Orthoclase
Albite
Plagioclase
KAlSi3O8
KAlSi3O8
NaAlSi3O8
(Na,Ca)Al(Si,Al)Si2O8
Mica
Biotite
Muscovite
Chlorite
K(Mg,Fe2+)3(Al,Fe3+)Si3O10(OH)2
KAl2(AlSi3)O10(OH)2
(Mg,Fe2+,Fe3+)AlSi3O10(OH)8
Clay
Kaolinite
Illite
Smectite
Chlorite
Al2Si2O5(OH)4
(H3,O,K)y (Al4 ⋅ Fe4 ⋅ Mg4 ⋅ Mg6)(Si8 – y ⋅ Aly)O20(OH)4
(Ca0.5Na)0.7(Al,Mg,Fe)4(Si,Al)8O20(OH)4 ⋅ nH2O
(Mg,Fe2+,Fe3+)AlSi3O10(OH)8
Carbonate
Calcite
Dolomite
Ankerite
Siderite
CaCO3
CaMg(CO3)2
Ca(Fe,Mg,Mn)(CO3)2
FeCO3
Sulfate Gypsum
Anhydrite
CaSO4 ⋅ 2H2O
CaSO4
Chloride Halite NaCl
Metallic oxide Iron oxides FeO, Fe2O3, Fe3O4
1000 gal
of 2% HF
350 lbm
of clay
12. Solubility of by-products
• When minerals are dissolved by HF, numerous by-products can form.
• Calcium fluoride
Some carbonates may remain after preflushing
Amount of carbonate cementing material in the sandstone
The carbonates’ initial protective siliceous coating
* CaF2 readily forms when calcite contacts HF.
This can lead to substantial damage:
Solubilityofby-products
12
Solubility in water at room temperature of HF reaction by-products
Secondary Product Solubility (g/100 cm3)
Calcium fluoride (CaF2) 0.0016
Sodium fluoaluminate (Na3AlF6) Slightly soluble
Sodium fluosilicate (Na2SiF6) 0.65
Aluminum fluoride (AlF3) 0.559
Aluminum hydroxide (Al(OH)3) Insoluble
Ferrous sulfide (FeS) 0.00062
CaCO3 + 2HF ↔ CaF2 + H2O + CO2
13. Kinetics: Factors Affecting Reaction Rates
• Weak cementation → reduced-strength mud acid (1.5% HF) → avoid crumbling
(Fogler et al., 1976)
• Fluoboric H3OBF4 → low concentration of HF
• Regular mud acid (12% HCl – 3% HF) is the normal concentration to use to
remove damage in clean quartzose sands.
• Field experience has shown that weaker concentrations (0.5% to 1.5% HF) can be
effective for other sands.
• If the combined percentage of clay and feldspar is more than 30%,
1.5% HF or less should be used.
Kinetics
13
Hydrofluoric Acid Concentration Hydrochloric Acid Concentration
14. Mud Acid Volume and Concentration
• Gidley (1985)
• Less may be used where only shallow damage exists around new perforations(75 gal/ft)
The HCl:HF ratio and concentration
are selected to prevent or reduce the
formation of damaging precipitates.
MethodsofControlling
Precipitates
14
More
than 125
gal/ft of
mud acid
Acid use guidelines for sandstone acidizing (McLeod, 1984)
Condition or Mineralogy Acid Strength (blend)
HCl solubility > 20% HCl only
High permeability (>50 md)
High quartz (>80%), low clay (<5%) 12% HCl–3% HF
High feldspar (>20%) 13.5% HCl–1.5% HF
High clay (>10%) 10% HCl–1% HF
High iron/chlorite clay (>15%) 10% acetic acid–1% HF
Low permeability (≤10 md)
Clay (<10%) 6% HCl–1% HF
Clay (>10%) 6% HCl–0.5% HF
15. The dissolution of minerals is a thermally activated phenomenon; thus, the rates increase
greatly as a function of temperature and the penetration depths of live acid diminish.
Figure :
The variation of the reaction rate of mud
acid with silica (more reactive than quartz)
as a function of both HF concentration and
temperature
Kinetics
15
Temperature
16. The relatively high total specific
surface area of sandstone rocks is
the primary parameter determining
mud acid spending.
Clays react much faster than feldspars, which react much faster than quartz
• An increase in pressure speeds up the overall dissolution reaction slightly.
Kinetics
16
Mineralogical Composition and
Accessible Surface Area
Pressure
Relative surface areas of sandstone minerals
Mineral Surface Area
Quartz <0.1 cm2/g
Feldspar Few m2/g
Kaolinite 15–30 m2/g
Illite 113 m2/g
Smectite 82 m2/g
17. Other Acidizing Formulations
• Problems related to the use of mud acid to remove damage in sandstone formations
Rapid spending provides only a short penetration.
Destabilization of Fines
The high dissolving power of mud acid
• New sandstone acidizing systems are designed to alleviate these shortcomings.
Fluoboric acid
Alcoholic mud acid
Mud acid plus aluminum chloride for retardation
Organic mud acid
Self-generating mud acid
Buffer-regulated hydrofluoric acid
OtherAcidizingFormulations
17
18. Summary of acids developed and under active research
Name, year, inventor Advantages Disadvantages Year of
research
Mud acid, 1965 Smith and
Hendrickson
Dissolves quartz, remove
damage
Corrosive, precipitation
reactions, fast reaction
1965–
present
Retarded mud acids, 1996, Al-
Dahlan
Reduces the reaction rate for
penetration (200 F)
Same problems at high
temperature and
formation of precipitates KBF4
1996–
present
Organic-HF acids, 1996,
Shuchart
Less corrosion rate, useful in HCl
sensitive clay (350 F)
Expensive, some precipitates
formed at high
temperature
1996–
present
10% acetic acid, 2003, Hartman Good results at higher
temperature
(100 F)
Only applicable where
carbonate percentage is
high
2003
Na3HEDTA and HEDTA
(chelating
agents), 2002 Ali, Frenier
Better results at high
temperature
(300 F)
No fluoride ion 2002–
present
Single-stage acid. (Goma, Cutler
2013)
Eliminates the use of pre-flush
and
after flush
Expensive, reaction mechanisms
not clear
2013–
present
Phosphoric–HF and Fluoboric–
formic,
2013 Shafiq
More permeability increase and
less
corrosion
Not used at high temperature,
reaction
mechanism unknown
2013–
present
OtherAcidizingFormulations
18
19. Methods of Controlling Precipitates
• The methods used to control the precipitates caused by acidizing:
MethodsofControlling
Precipitates
19
Proper Acid Staging
Lower Acid Concentration
Correct Usage Preflush and Sufficient Overflush
20. Preflush Stage
The preflush displaces formation brine away from the wellbore to prevent it from
mixing with reacted mud acid and causing a damaging precipitate.
To dissolve any Na, K and Ca ions that may produce insoluble silicates when
reacted with the silica.
Preventing the live HF acid to enter into a high pH region.
Pre-flush also provides a low pH region reducing the risk of precipitate
formation.
• Preflush with
MethodsofControlling
Precipitates
20
1. 5% to 15%
HCl
Acetic Acid
21. MethodsofControlling
Precipitates
21
Fluid selection guidelines for preflush fluids
Mineralogy Permeability
>100 md
Permeability
20 to 100 md
Permeability
<20 md
<10% silt and <10% clay 15% HCl 10% HCl 7.5% HCl
>10% silt and >10% clay 10% HCl 7.5% HCl 5% HCl
>10% silt and <10% clay 10% HCl 7.5% HCl 5% HCl
<10% silt and >10% clay 10% HCl 7.5% HCl 5% HCl
If the formation contains more than 1% to 2% carbonate
Solution: HCl preflush is necessary to dissolve the carbonate, prevent the waste of mud acid.
If completion brines such as seawater, potassium chloride (KCl), calcium
chloride (CaCl2) have been used in the well prior to acidizing.
Solution : Preflushing the mud acid with HCl or brine containing ammonium chloride (NH4Cl) to
dilute the brines
Preflushes can also be used to displace and isolate incompatible formation
fluids (either brine or crude oil)
22. To dissolve the quartz, clay, feldspar and silicates.
This acid may also dissolve the remains of carbonates present after the pre-
flush stage
MethodsofControlling
Precipitates
22
Fluid selection guidelines for mud acid fluids
Mineralogy Permeability
>100 md
Permeability
20 to 100 md
Permeability
<20 md
<10% silt and <10% clay 12% HCl–3% HF 8% HCl–2% HF 6% HCl–1.5% HF
>10% silt and >10% clay 13.5% HCl–1.5% HF 9% HCl–1% HF 4.5% HCl–0.5% HF
>10% silt and <10% clay 12% HCl–2% HF 9% HCl–1.5% HF 6% HCl–1% HF
<10% silt and >10% clay 12% HCl–2% HF 9% HCl–1.5% HF 6% HCl–1% HF
Main acid stage
23. Postflush or Overflush
It cleans the formation rapidly by removing the spent acid.
To displace mud acid reaction products away from the wellbore
Is used to keep the wettability of the formation to the original state
To displace non-reacted mud acid into the formation
MethodsofControlling
Precipitates
23
Typical overflushes for mud acid treatments are
• Water containing 3% to 8% ammonium chloride
• Weak acid (3% to 10% HCl)
• Diesel oil (oil wells only and only following a water or weak acid
overflush)
• Nitrogen (gas wells only and only following a water or weak acid
overflush)
24. Matrix Acidizing Design Guidelines
• McLeod etal. (1983), who recommended the following steps for treatment design:
1) Estimate safe injection pressures.
2) Estimate safe injection rate into the damaged formation.
3) Select stages required for fluid compatibility.
4) Calculate volume of each stage required.
5) Select acid concentrations according to formation mineralogy.
MatrixAcidizingDesignGuidelines
24
Formation brine displacement
HCL stage or acetic acid stageCrude oil displacement
Mud acid stage
Overflush stage
Allowable safe injection pressure at both the wellbore and at the surface
Present bottomhole fracturing pressurePresent fracturing gradient
25. Calculation
• Fracturing pressure
• Matrix treatments are defined as fluid injection occurring below fracturing
pressure. If the fluid is injected above fracturing pressure, the acid may
bypass the damage.
• Injection rates:
• qi,max is the injection rate in bbl/min
• k is the effective permeability of the undamaged formation in md
• h is the net thickness in ft
• gf is the fracture gradient in psi/ft
• H is the depth in ft
• Δpsafe is the safety margin for the pressure in psi (usually 200 to 500 psi)
• p is the reservoir pressure in psi
• μ is the viscosity of the injected fluid in cp
• re is the drainage radius in ft
• rw is the wellbore radius in ft
• s is the skin effect factor
• B is the formation volume factor and has a value of 1 for noncompressible fluids
MatrixAcidizingDesignGuidelines
25
26. • Friction pressure estimation
Accurate fluid friction pressure is a difficult paramete to obtain. Because the tubular arrangement can be
different in each case
• ppipe friction is the friction pressure in psi/1000 ft
• ρ is the density of the fluid (specific gravity) in g/cm3
• q is the pump rate in bbl/min
• D is the diameter of the pipe in in
• Fluid volumes
• Vp is the pore volume for the distance s in gal/ft
• φ is the fractional porosity
• rs is the distance it is necessary to penetrate the
damaged or displaced section in ft
• Volume HCL
• VHCl is the volume of HCl required in gal/ft
• XHCl is the fraction of the bulk rock dissolved by HCl
• β is the dissolving coefficient expressed as the amount
of rock dissolved per gallon of acid and is related to the acid strength
MatrixAcidizingDesignGuidelines
26
27. Acid Treatment Design Considerations
Selection of Fluid Sequence Stages
• The preflushes, main stage and overflush should be matched to the type of
damage.
Cleaning (Tubing Pickle)
• remove rust, scale and organic deposits
*Scale Occur in wellbore, Usually results in a sharp drop of production
Such as Iron Sulfide, Iron carbonate
*Organic deposits, Commonly located in tubing
Such as Wax, Paraffins or Asphaltenes
• dissolve oily films and pipe dope that could plug the downhole equipment and
perforations
• limit the amount of iron that gets into the formation and contacts the crude oil.
AcidTreatmentDesign
Considerations
27
28. Acid treatment sequence and fluid options
Stage Fluid System
1. Preflush Brine
Hydrocarbons
HCl
2. Main fluid HCl-HF formulation
3. Overflush HCl or NH4Cl
4. Diverter Foam or slug OSR
5. Repeat stages 1–4 as necessary with 1–3 as
the last fluid sequence
6. Fluoboric acid With diverter solvent for OSR or foam-
weakening agent
(mutual solvent)
7. Fluoboric acid diverter Fluoboric acid–based fluid system, either
foamed
or slug OSR
8. Fluoboric acid Fluid left at the perforations
AcidTreatmentDesign
Considerations
28
Diversion techniques
• This is an excellent way to ensure that the main fluid stages are properly isolated by
the preflush and overflush fluids.
• Diversion should be matched to formation characteristics and the type of treating
fluid.
Typical Sandstone Acid Job Stages
29. Typical stage sequence for a sandstone acidizing treatment
Stage Number Stage Reason for Stage Information Source Stage Composition Stage Volume
1 Crude oil displacement To prevent oil sludge
formation by the acid
Acid–crude oil sludge test Aromatic solvent To achieve 3-ft radial
displacement
2
Formation water
displacement
To prevent scale
deposition
HCO3 and SO4 contents
from formation water
analysis
Ammonium chloride
(NH4Cl) at 3%–8%
depending on the salinity
of the formation
water
To achieve 3-ft radial
displacement
3 Acetic acid
Iron compounds in
formation (pyrite,
siderite, hematite),
chlorite, clay, zeolites
X-ray-diffraction (XRD)
analysis
3%–10% acetic acid
CaCO3 (%) Volume (gal/ft)
0–5
5–10
10–15
15–20
25
50
75
100
4 Hydrochloric acid CaCO3 or other HCl-
soluble minerals
HCl solubility test and/or
XRD analysis
According to core
mineralogy: 3%–15% HCl
Calculated on the basis of HCl
solubility and porosity or this
schedule:
HCl Solubility Stage
Volume
of HF (%) (gal/ft)
<5
5–10
10–20
50
100
200
5
Hydrofluoric acid (not
used for carbonates and
sandstones where HCl
solubility > 20%)
To remove clay, other
formation fines and mud
damage
XRD analysis, SEM
analysis HCl:HF
solubilities
According to formation
mineralogy: 3%–13.5%
HCl with 0.5%–3% HF
75–100 gal/ft
6 Overflush
To spend acid and flush
spent acid away from the
near-wellbore area
Always used
3%–8% NH4Cl or 3%–5%
HCl in all wells followed
by nitrogen (gas wells),
kerosene (oil wells) or 5%
HCl (water injection
wells)
One to two volumes of the HCl:HF
volume or to achieve 5-ft radial
displacement
7 Diversion To improve injection
throughout the interval
Used as required for
heterogeneous formation
permeability
OSR for oil or low gas/ oil
ratio wells, foam for
either oil or gas wells and
water-soluble resins for
water injector wells
29
AcidTreatmentDesign
Considerations
31. WhyAcidizingisPreferredOverHydraulicFracturinginSandstoneFormation?
• Sandstone Acidizing can be used instead of hydraulic fracturing
in many cases like
High permeability formation and naturally fractured reservoirs.
Sandstone acidizing can be utilized in depleted sandstone
reservoirs for CCS.
• carbon capture storage is the process of capturing waste carbon dioxide
(CO2) from large point source, such as fossil fuel power plant, transporting it to
a storage site, and depositing it where it will not enter the atmosphere, normally
an underground geological formation
Acidizing can be used at different temperatures and pressures.
(Abdelmoneim and Nasr-El-Din 2015).
79% of the stimulation jobs were acid treatments, they are a
low cost than hydraulic fracturing treatment, they only
consumed 20% of the money spent for well stimulation. (Collier
2013)
Whyacidizingispreferredover
hydraulicfracturing?
31
32. 32
Damage Identification
Knowledge of Chemical
Reaction
Select of Appropriate Types
and Volumes of Preflushes and
Overflushes
Use Numerical Simulator
Evaluating The Executed Acid
Treatment
Conclusion
33. References
Reservoir Stimulation, Third Edition
By Michael J. Economides, Kenneth G. Nolte
Production Enhancement with Acid Stimulation, Second Edition By
Leonard Kalfayan
Oilfield Review, Sandstone Acidizing
Harry O. McLeod, Conoco, USA
William David Norman, Schlumberger Dowell
Oilfield Review, Schlumberger, wniter 2008/2009
High-Temperature Well Stimulation, Salah Al-Harthy Houston, Texas, USA
Sandstone matrix acidizing knowledge and future development, 2017
Mian Umer Shafiq
Hisham Ben Mahmud
References
33
