Lecture 9: Well Stimulation

by
Muhammad Mohsin Yousufi
Oil and Gas Production Facility Design (PE-413)
Petroleum Engineering Department NEDUET

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Lecture Outline

Outline
• Carbonate Matrix Acidizing
• Case Studies

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 Carbonate Matrix Acidizing
Diversion
Wellbore cleanout Pre-Flush Main Acid Treatment Over-Flush

Displacement
There are 3 stages during Acid-Rock interaction:
+
1. Transfer of H ions to the rock surface,
+
2. Reaction of H ions with the rock content,
3. Transfer of products (generated) from rock surface the fluid.

“The slowest stage controls the overall reaction rate”

For Limestone:
+ +
CaCO3 + 2H ↔ Ca2+ + CO + 𝐻2 O
2
For Dolomite:
+ + +
CaMg (CO3 )2 + 4H ↔ Ca2+ +Mg 2+ +2CO2 + 2𝐻2 O
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Concerns
3 issues generally need to be dealt with
• Fast Reactivity
• Fluid Loss
• Precipitation

Concern Effects
Fast Reactivity Rapid consumption, reduces
Multi-wormhole generation
and prevent maximum depth
penetration
Fluid Loss Reduces Multi-wormhole
generation and Prevent
maximum depth penetration

Precipitation Increases impermeability

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 Case Study 1
Formation Type: Shaly-Sandstone (Quartz, Feldspar, Clay, Lithic fragments)
(Clay and Feldspar content varies between 20-40%)
Field Production: Oil & Gas
Temperature: 120°F-140°F
Challenge: Damage removal and fines stabilization to combat declining production
at low temperature

Prior Action Taken: Acid Treatment (HF+Clay Stabilizers) used proved to be

ineffective due to low temperature, which slowed down the clay dissolution rate.
Short term production increase  ↓Production in 3 months below pretreatment
level

Treatment:
HF+HBF4 + Acetic Acid
HBF4=Boric acid + Ammonium bifluoride + HCl
(Boric Acid: H3BO3, Ammonium bifluoride:NH3F.HF)

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Case Study 1
Chemical Function
HBF4 Deep live- acid penetration
+clay fines stabilization
Acetic Acid Chelates Al3+ ions, keeps silica
in the solution, prevents
precipitation of Al[OH]3
HCl Minimizes Secondary/Tertiary
precipitates in sensitive
formations

Results:
• System intended to work between 100-140°F in clay formation
• Initial production of well increased by 200% (shortly).
• Maintained 100% long term,
• Removed and stabilized clay content
• No need to retreat the well
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Fluoroboric acid

• Less reactive than Mud Acid

• Less content of HF
• Provides permanent stabilization of silica clays and
fines
• Eliminates Water sensitivity
• Can be used pre-flush, over-flush or main-flush in
Sandstone Acidizing
• As main-flush pre-flush of HCl is required
• Should not be over-flushed to obtain maximum
stability
• Requires long shut-in times due to slow reactivity

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Case Study 2
Formation Type: Limestone (k=4mD and Φ= 12vol.%)
Field Production: Oil
Temperature: 160°F
Well Depth: 7785ft (7 inch completed with 23/8inch N-80)
Perforation Extension: 7700-7717ft
Perforation Density: 4 shots/ft.
Gas Injection Point: 5400ft
Well Skin Damage: +11
• A recent buildup test indicated reservoir pressure to be 2900psi.
The flowing wellhead pressure to be 80psi, the oil production
175B/D. The productivity index was 0.2B/D/psi at zero water cut.
• Oil is produced via Gas lift using natural gas below bubble point
Prior Treatment: Well was stimulated using 28wt.% HCl with 5vol.%
Mutual solvent. The well responded adversely.
A bottom hole sample indicated presence of Asphaltene.
Objective: To increase injectivity of well using E.A.
Treatment: Conducted in 2 stages
1)40 gal/ft. of 15wt.% HCl
2)40 gal/ft Emulsified Acid (consisting of Xylene) 8
Case Study 2
• Acids were placed using 1.5 inch Coiled Tubing
• Xylene was checked for compatibility with rubber seals
• Safety precautions against flammability were taken
• Wellhead pressure was during pre-flush which declined after 700 gallon injection of
acid  Indicating injectivity improvement
• EA injected: Well pressure dropped drastically indicating  Asphaltene dissolution
by Xylene
• Acid was soaked for 1.5 hours and spent acid was lifted using N2 gas

Results:
Regular acid did create wormholes and improved injectivity
Further enhanced by dissolving of Asphaltene and permeability increase by EA
The well produced 750B/D at 120psi with no water no water-cut
Treatment was applied in 3 more wells, with only one well having water-cut (that was
due to prior treatment implementation).

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Case Study 2
Content Values
Acid to Oil Ratio 70:30
HCl 15wt%
Corrosion Inhibitor 9 Gallons
Inhibitor Intensifier 8 Gallons
Anti-sludge Agent 7 Gallons
Surfactant (Non-ionic) 3 Gallons
Iron Control Agent 4 lbs.

Before After
Well Oil Rate (B/D) Water Cut Oil Rate (B/D) Water Cut
1 175 --- 750 ---
2 64 20 180 40
3 120 --- 370 ---
4 160 --- 350 ---
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Case Study 3
Formation Type: Naturally fractured reservoir, Limestone (97%) and Shale (3%),
K=30 mD and Φ= 8vol.%
Field Production: Oil
Temperature: 279°F
Drilled Depth: 15,150ft
Drilling Fluid: Oil based Mud
Perforated Interval: 14,180-14190ft
Reservoir Pressure: 1930 psi, Oil Gravity: 35°API, Water Saturation: 15%,

Drilling fluid losses of up to 440bbl in production zones occurred. As simulation

model it was predicated that the drilling mud invaded critical matrix and
plugged the fractured system thus reducing well productivity.
Laboratory tests for drill cutting, oil sample and stimulation fluid were
conducted which supported the model.

Objective: To maximize Acid penetration and by pass damage zone

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Case Study 3
Treatment: 2 stage
Cleanout Stage: Nonreactive fluid based solvent for damage removal to
disperse emulsions and clean drilling mud from the rock
Main Acidizing Job: Containing a mixture of additives with the main
acidizing medium

Chemical Function
Emulsified Acid (15wt.%) Retardation Effect
Mud & Silt Remover (15%) Removal of Mud and Silt
Particles
Self Diverting Agents To improve fluid zonal
coverage along the entire
perforated interval

Result: The treatment increased production by 162% (2100B/D)

More than expected 800B/D
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