4.

3 Well Stimulation
 Objectives

 Matrix Stimulation
 Reactive Stimulations
‐ Sandstone
‐ Carbonate
 Non-reactive Stimulations

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 Well Stimulation
Method to increase well productivity by either reducing skin (S) or
increasing permeability-thickness (Kh).
 Matrix stimulation (remove formation damage)
 Reactive (acidizing)
 Non reactive (solvents/surfactants)
 Acid fracturing (low k carbonates or remove damage in high
k sandstones)
 Hydraulic fracturing (low k sandstones)

Removal of near wellbore impairment reduces skin or allows more

formation height may be connected with the wellbore, showing up as
an increase in Kh

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 Matrix Stimulation
The treating fluid is pumped into the well at a bottom hole
injection pressure which value does not exceed the mechanical
resistance of the rock.

  re  
142.1q Bo  ln
r 
 s
Pi    w   P
e
kh

Pi is the bottom hole injection pressure Pe the reservoir

pressure.
Knowing the fracture pressure is required to stablish the limit
of Pi.

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 Matrix Stimulation

4,5

4
FRACTURE PRESSURE
3,5
PRESSURE, Mpsi

2,5

1,5

0,5

0
0 1 2 3 4 5 6 7 8 9 10
PUMPING RATE, BPM

.
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 Matrix Stimulation
SELECTION OF TYPE OF CHEMICAL TREATMENT
SOURCE OF DAMAGE TYPE OF DAMAGE MATRIX TREATMENT

DRILLING, COMPLETION AND CHANGE IN WETTABILITY SOLVENT/SURFACTANT

STIMULATION FLUIDS
EMULSIONS SOLVENT/ SURFACTANT

SCALES (Carbonates) ACID / INHIBITOR

WATER BLOCKAGE SURFACTANT / SOLVENT

PRODUCTION FINES MIGRATION ACIDIZING

CLAY MIGRATION / SWELLING ACIDIZING

SCALES ACID / /INHIBITOR

ORGANIC DEPOSITS SOLVENT / THERMAL /

(WAXES, ASPHALTENES) MECHANIC

INVASION OF SOLIDS FROM PLUGGING BY SOLIDS ACIDIZING

DRILLLING MUD, COMPLETION
FLUIDS OR STIMULATION FLUIDS

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 Reactive Stimulations
Types of acids and additives
1.- Fundamentals
• Hydrochloric acid, HCl (Carbonates)
• Hydrofluoric acid, HF (Fines, Clays and Sandstones)
• Acetic acid, CH3- COOH (carbonates dissolution at high
temperatures)
• Formic acid HCOOH (carbonate dissolution at very high
temperatures)
2.- Special combinations and formulations
• Mud-Acid: Mixture of HCl y HF
• Acid to remove debris from perforations
• Fluorboric acid (stabilizes clay fines)
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 Reactive Stimulations
Acid modifications by additives
Indispensable Additives
• Corrosion inhibitor (Prevent damage to casing and
tubing)
• Iron stabilizer (Prevent Fe(OH)3 deposition)
• Surfactant (Prevent emulsions and sludges)
Any other additive is optional and the necessity to use it, must
be demonstrated by doing compatibility tests with formation
fluids.

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 Reactive Stimulations
Formation Treatment Response

Prediction of the reaction of the rock and saturating fluids with the
alive and wasted acid.
1. Which volume of formation will be dissolved by the acid
(solubility tests)

2. Which volumen of formation will be dissoved in HCl-HF.

3. Which products will precipitate as a consequence of these

reactions.

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 Reactive Stimulations
Components of an acid treatment

1 Preflush
• Avoid contact of the acid with the crude oil.

2 Treatment
• Mixture of acid designed to remove damage.

3 Over displacement
• Push the acid to the limit of critical area with gasoil , solvent,
nitrogen.

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 Design of a Chemical Matrix Treatment

Injection Pressure and Rate

Optimum Conditions:
• Maximum rate and maximum pressure without fracturing the formation.
• A previous injectivity test must be done or the fracture gradients of the area
must be taken.

  re  
142.1q Bo  ln
r 
 s
Pi    w   P
e
kh

For safety reasons, Pi must be 500 psi lower than the fracture
pressure

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 Reactive Stimulations
Basics mechanisms of Interaction between acid and
rock minerals

STOICHIOMETRY: Amount of rock dissolved for a

given amount of acid expended.

REACTION KINETICS: Rates at which acids react with

various minerals.

DIFFUSION RATES: How rapidly acid is transported to

the rock surfaces.

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 Reactive Stimulations
STOICHIOMETRY
Reaction between HCl and Calcite

2HCl + CaCO3 CaCl2 + CO2 + H2O

DISSOLVING POWER FACTOR ( β ) FOR DIFFERENT HCl

SOLUTIONS (ft3 CaCO3/ ft3 HCl)

HCl Concentration (%) β

5 0.026
10 0.053
15 0.082
30 0.175

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 Reactive Stimulations
STOICHIOMETRY
Reaction between HF and Silicate Minerals

4HF + SiO2 SiF4 + 2 H2O

SiF4 +2HF SiF4 + 2 H2O
DISSOLVING POWER FACTOR ( β ) FOR DIFFERENT HF SOLUTIONS
(ft3 SiO2/ ft3 HF)

HF Concentration (%) β

2 0.006
3 0.010
4 0.018
6 0.019
8 0.025
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 Reactive Stimulations
Precipitation of acid reaction products

In sandstone acidizing:

2HF + CaCO3 CaF2 + CO2 + H2O (fast)

Colloidal Silica Si(OH)4 (slow)

Ferric Hydroxide Fe(OH)3 (present in iron bearing minerals

or dissolution of rust tubing)
Asphaltene sludges (contact of acid with some crude oils)

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 Effect of Shifting an 80% Damage Collar
Percent of original productivity

100
3-in collar

6-in collar
80 12-in collar
rc-rx = collar thickness
Damage collar
60 rc

40 rx

Wellbore
20 re

0
0 1 2 3 4 5 6
Inner radius of damage (ft)

16
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 Acid Selection

STANDARD TREATMENTS

Carbonates: 15%WT HCl

Sandstones: 3%HF, 12% HCl, preceded

by 15% HCl (pre-flush)

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 Reactive Stimulations
Acid modifications by additives
Indispensable Additives
• Corrosion inhibitor (Prevent damage to casing and
tubing)
• Iron stabilizer (Prevent Fe(OH)3 deposition )
• Surfactant (Prevent emulsions and sludge)

Any other additive is optional and the necessity to use it,

must be demonstrated by doing compatibility tests with
formation fluids.

DO NOT EVER USE UNNECESSARY ADDITIVES

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 Acid Selection
Sandstone Acidizing
HCl solubility >20% Use HCl only

High Permeability (100 mD plus)

High quartz (80%), low clay (<5%) 10%HCl - 3%HF (a)

High Feldespar (>20%) 13.5%HCl – 1.5%HF (a)

High clay (>10%) 6.5%HCl – 1%HF (b)

High iron chlorite clay 3%HCl – 0.5%HF (b)

Low Permeability(10 mD or less)

Low Clay(<5%) 6%HCl - 1.5%HF (c)

High Chlorite 3%HCl – 0.5%HF (d)

(a) Preflush with 15% HCl (b) Preflush 5% HCl + iron stabilizer
(c) Prefluysh with 7.5%HCl or 10% acetic acid (d) Preflush with 5% acid acetic

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 Acid Selection
Carbonate Acidizing
Perforating Fluid 5% acetic acid
Damaged Perforations 9% formic acid
10% acetic acid
15% HCl
Deep Wellbore damage 15% HCl
28% HCl
Emulsified HCl

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 Design of a Chemical Matrix Treatment

400 F 5% V= r2h, for h= 1 400

Required Volumes (gallons/ft)

350 F 10% 350

300 300
F 15%
250 250
200 F 20% 200
150 150
F 25%
100 100
50 50
0 0
0 0,5 1 1,5 2 2,5 3 3,5 4 4,5 5 5,5 6 6,5 7 7,5 8
PENETRATION RADIUS (FEET)

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 Real Time Monitoring and Evaluation of an
Acid Stimulation
1.- Paccaloni Method
 Q   rb 
Pi  ( Pe  Ph  Pfr )  141.7  ln  s 
 Kh   rw 
Pi = Surface pumping pressure, psi
Pe= reservoir pressure, psi
Ph= Hidrostatic pressure, psi
Pfr= Friction losses, psi
Q= Injection rate, b/d
µ= Fluid viscosity, cp
K= Effective permeability of the injected fluid, md
h= Formation thickness, feet
rb= Radius of the ijected fluid bank, feet
rw= Well radius, feet
s= Skin factor, dimensionless
Based on this equation, a plot of injection pressure versus rate is prepared,
taking S as the parameters of the curves
22 Copyright ©2012 NExT. All rights reserved
 Real Time Monitoring and Evaluation
of an Acid Stimulation
PACCALONI METHOD
10000 Surface Frac Pressure
SURFACE PRESSURE, PSI

9000
8000 S=10 S=5 S=2 S=0
7000 S=-2

6000
S=-3
5000
4000
3000 Friction Losses
2000
1000
0
0 1 2 3 4 5
INJECTION RATE (bpm)

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 EXERCISE # 14 A

A well is draining oil from a reservoir which matrix contains 10% Vol CaCO3
and no other HCl soluble mineral and has an initial porosity of 20 %. Wellbore
radius = 0.5 ft

A. Calculate the volume (gal) of 15% wt HCl needed to dissolve all

carbonates to a distance of 2.5 ft (rs = 3.0 ft) from the wellbore (Pre-flush).
Reservoir thickness = 60 ft.
B. Calculate the volume (gal) of 15% wt HCl needed to fill in the pore volume
at a distance of 2.5 ft (rs = 3.0 ft) from the wellbore assuming that all
CaCO3 has been removed.
C. Calculate total pre-flush = A+B

Notes: 1 ft3 = 7,48 gal

Dissolving power factor of HCl 15% = 0,082 ft3 CaCO3/ ft3 HCl

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 EXERCISE # 14 A

rw=0.5 ft rs=3 ft

h=60ft

Sol

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 Non-Reactive Stimulations
Other, less common causes of damage include emulsions and sludges,
wettability alteration and water blocks.

Water in oil emulsion

Oil in water emulsion

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 Non-Reactive Stimulations
 The mixing of two immiscible fluids at a high shear rate in the
formation can sometimes result in the formation of a
homogeneous mixture of one phase dispersed into another, in
the near-wellbore region. Such emulsions usually have a higher
viscosity than either of the constituent fluids and can result in
significant decreases in the ability of the hydrocarbon phase to
flow.
 Among the most common solids that stabilize emulsions are iron
sulfide, paraffin, sand, silt, clay, asphalt, scale and corrosion
products. Emulsions are typically treated using mutual solvents
and surfactants.

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 Treatment of Emulsions
in the Reservoir
SOLVENTS + SURFACTANTS

SOLVENTS
They are chemical compounds capable of dissolving another
substance, producing a homogeneous mixture.
The most widely used in the oil industry are mono-aromatic
solvents such as toluene, xylene, and diesel oil.

SURFACTANTS
Chemicals which are located at the interface between two fluids, by
modifying the interfacial tension.
Nonyl-phenols and nonyl-phenol ethoxylates are nonionic
surfactants, or detergent-like substances, with uses that lead to
widespread release into aquatic environments.

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 Acidizing and Matrix Treatment

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 Matrix Treatments

– Matrix Treatments are those injected at a

pumping rate below fracturing rate.
– In a Matrix Treatment, the injection pressure
is always below the fracturing pressure.

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 Sandstone Formation
– Acid work – Frac work
• 0.63 $/boe – 0.68 $/boe
140

120

100 Sand

1000’s
Acid
BOPD 80 Gas
Added
60 Water
Scale
40 Frac
20

0
1994 1995 1996 1997 1998
31
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 Matrix Success Rate

– ARCO study (1990 - 1992 at Thumbs)

• Fracturing failure rate = 5%
• Matrix acid failure rate = 32%
– Amoco study (1994 - 1996 in Permian Basin)
• Acid jobs pay-out < 40% of the time
• Texaco and Chevron had similar results in the area.
– Hassi-Messaoud Field (SPE 39485)
• 1995: positive gain 68% (ave 1.11 m3/hr)
• 1996: positive gain 74% (ave 1.35 m3/hr)
• 1997: positive gain 78% (ave 2.34 m3/hr)
– Why?

32
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 Why are there failures?

– Damage identification
ScaleSOLV
Production BPD

1400
HCl Mud Acid

1000

600

200
0
15 Months
OIL

WATER
33
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 Why are there failures?
• Lift optimization: 33% of all failures occurred because
fluid level could not be reduced. ESP installed

10000 100
bopd
bwpd 98

mcfpd 96
1000 fluid above pump
94
Water Cut

Water Cut, (%)

Production

92

100 90

88

86
10
84

82

1 80
34 3/11/98 4/25/98 6/9/98 7/24/98 9/7/98 10/22/98 12/6/98 1/20/99 3/6/99

34 Copyright ©2012 NExT. All rights reserved

 Why are there failures?

– Placement
40

30

20
Change in Water Cut (%)

FOAMMAT DIVERSION SERVICE

10
POST-JOB WATER CUT: 18.8%
0

-10

WITHOUT DIVERSION
-20
POST-JOB WATER CUT: 45.5%
-30

35 -40
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 Why are there failures?

– Damage characterization
– Artificial lift
– Placement
– Fluid-fluid incompatibility
• Emulsions
• Sludge (asphaltenes, iron hydroxide)
– Insufficient acid volume
– Precipitation of reaction by-products
• Poor fluid selection
• Improper acid flowback procedures
– Water block
– Improper candidate selection
36
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 Establish Production Potential
Pressure

Gap
37
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Flow Rate
 Major Goal of Matrix Treatment

• Restore natural permeability

• By treating the critical matrix

38
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 Effect of Shifting an 80% Damage Collar

Percent of original productivity

100
3-in collar

6-in collar
80 12-in collar
rc-rx = collar thickness
Damage collar
60 rc

40 rx

Wellbore
20 re

0
0 1 2 3 4 5 6
Inner radius of damage (ft)

39
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 Hawkin’s equation
 k  rd
s    1 ln
 kd  rw
45
40
35
30
k/kd=3
25
skin

k/kd=5
20
k/kd=10
15
10
5
0
0 10 20 30 40 50
rd

40 Copyright ©2012 NExT. All rights reserved

 Change in Damage Skin Factor

– Matrix acidizing
• Sandstone: skin can be reduced to zero at best
• Carbonate: can generate a negative skin
– Fracturing
• A negative skin is possible
Completion Skin
Fracture -6 to -2
StimPAC -2 to +4
Open hole 0 to +5
OH gravel pack +2 to +10
Cased hole +2 to +15
CH gravel pack +5 to +20
41
41 Copyright ©2012 NExT. All rights reserved
 Summary

– Damage in the critical matrix is the target of

matrix stimulation.
– Wells without a performance gap will not
respond well to matrix treatments.
– A successful stimulation treatment is one that
yields the predicted production and ROI/Pay
Out.
• Damage characterization
• Fluid selection
• Placement
• etc.
42
42 Copyright ©2012 NExT. All rights reserved
 Matrix Treatment Fluids

– Any fluid able to dissolve the damage material

(sandstone) or by-pass the damage material
(carbonate).
– Normally, more than one fluid are used: either,
several fluids are used to treat different damage
or a suite of fluids are used for a single type of
damages.
– The fluids most commonly used are aromatic
solvents and acids (HCl, Mud Acid).
43
43 Copyright ©2012 NExT. All rights reserved
 Sandstone Acidizing

– The main sandstone acidizing fluid is a mixture of HCl

and HF called Mud Acid
• Mud Acid = HCl – HF

– A Mud Acid treatment includes:

• HCl preflush
• Mud Acid (HCl-HF) main treatment acid
• HCl or NH4Cl overflush

44
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 Carbonate Acidizing

• The Acid used to dissolve carbonates and by-pass

damage is:

HCl

45 Copyright ©2012 NExT. All rights reserved

 Acidizing
For sandstone
 The main sandstone acidizing fluid is a mixture of HCl and HF
called Mud Acid
• Mud Acid = HCl (12%) – HF (3%)
 A Mud Acid treatment includes:
• HCl preflush
• Mud Acid (HCl-HF) main treatment acid
• HCl or NH4Cl overflush
For carbonate
 The Acid used to dissolve carbonates and by-pass damage is
HCl

47 Copyright ©2012 NExT. All rights reserved

 Fluids Placement

– Bullheading the treatment

– Use of Coiled Tubing
– Diversion
• Diversion with Packers
• Diversion with Chemical Additives
• Diversion with Foam
• Self-Diverting Fluids
48
48 Copyright ©2012 NExT. All rights reserved
 Mechanical Methods of Diversion (1)
wireline
Acid Pump
fluid flow
Protective
Fluid Pump

frac baffle

diesel
cast iron bomb
interface locator

acid

49
49 Copyright ©2012 NExT. All rights reserved
 Mechanical Methods of Diversion (2)

CT or workover Ball Sealers

rig controlled PPIT

conventional buoyant
density ball sealer
ball sealer

50
50 Copyright ©2012 NExT. All rights reserved
 Chemical Divertors
• Soaps (1936)
• Cellophane flakes
• Naphthalenes (1954)

• Rock Salt
• Benzoic acid
• Wax-Polymer Blends
• Hydrocarbon Resins

51 Copyright ©2012 NExT. All rights reserved

 Guidelines for Staging Treatments

Recommended number of treatment stages for all

staged treatments
Perforated Acid Diverter Design
Interval (ft) Stages Stages (Ft)
20 2 1 10’
40 3 2 15’
60 3 2 20’
80 4 3 20’
100 5 4 25’
125 5 4 25’
150 6 5 25’
175 7 6 25’
200 8 7 25’
225 9 8 25’
250 10 9 25’
52
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 Foam Diversion

gas

acid

rock

53
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 Foam Diversion (method)

Preflush
Stage Foam
Stage Acidizing Stage
(contains foamer)
1.0
Flow rate (BPM/20 ft zone)

0.75 Damaged Zone

Shut-in
0.5 Period

0.25 Former Thief Zone

0
0 10 20 30 40 50 60 70 80 90 100
Time (min)
54 Copyright ©2012 NExT. All rights reserved
 Foam Diversion (step 1)

Damaged Zone

Thief Zone

– Clean the near wellbore area

– Displace oil or condensate
55
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 Foam Diversion (step 2)

Damaged Zone

2 1 Thief Zone

– Saturate the near wellbore region with foamer

– Remove damage form the thief zone
56 – Saturate the rock with foamer to stabilize the foam
56 Copyright ©2012 NExT. All rights reserved
 Foam Diversion (step 3)

Damaged Zone

2 Thief Zone
1

•Foam injection
– Foam bank is formed in both layers
57
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 Foam Diversion (step 4)

Damaged Zone

2 Thief Zone
1

•Shut-in period
– Foam dissipates rapidly in damaged
58 zone
58 Copyright ©2012 NExT. All rights reserved
 Foam Diversion (step 5)

Damaged Zone

2 Thief Zone
1

– Inject treating fluid containing foamer

– Acid preferentially flows into low perm
59
layer
59 Copyright ©2012 NExT. All rights reserved
 Viscoelastic Technology (VES)

– OilSEEKER is based
on VES technology. OilSEEKER
• Contains no solids, Mw = 450

polymer or nitrogen
• Very easy to mix and
pump in the field
– It selectively plugs the 10000

high-water-saturation

Apparent Viscosity [cP]

OilSEEKER
zones, causing acid to 1000

enter the high-oil- 100

HEC
saturation zone.
– Compatibility testing 10

must be performed 60
1
0.01 0.1 1 10 100 1000
60 Copyright ©2012 NExT. All rights reserved
Shear Rate [sec-1]
 Core Test with VES at 150°F
1
0.9 Oil Zone
0.8 410 md with 80% water saturation
Fraction of Flow

0.7
0.6
0.5 3%NH4Cl 10% U66 3%NH4Cl Oil Seeker 15% HCl

0.4
0.3
390 md with 20% water saturation
0.2
0.1 Water Zone
0
0 20 40 60 80 100 120 140 160 180

Time (min)
61
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