INTRODUCTION TO HYDROCARBON EXPLOITATION

Development Phase

Introduction to Hydrocarbon Exploitation

Stimulation Techniques

Pratap Thimaiah

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Characterizing Damage and Stimulation

1. List causes of damage skin

2. List causes of geometric skin
3. Calculate skin from pressure drop
4. Calculate flow efficiency from skin
5. Calculate skin factor and wellbore radius
6. Convert skin to fracture half-length
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Damage Caused by Drilling Fluid

Mud filtrate
invasion
Well Stimulation

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Damage Caused by Production

p < pb p > pb

In an oil reservoir, pressure near well may be below bubble

point, allowing free gas which reduces effective permeability
to oil near wellbore.
Well Stimulation

In a retrograde gas condensate reservoir, pressure near well

may be below dew point, allowing an immobile condensate
ring to build up, which reduces effective permeability to gas
near wellbore.
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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Damage Caused by Injection

“dirty” incompatible
water water

Injected water may not be clean - fines may plug formation.

Injected water may not be compatible with formation water -
may cause precipitates to form and plug formation.
Well Stimulation

Injected water may not be compatible with clay minerals in

formation; fresh water can destabilize some clays, causing
movement of fines and plugging of formation.

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Reservoir Model of Skin Effect

Bulk
formation
Altered
zone

ka k
h
Well Stimulation

rw

ra

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Reservoir Pressure Profile

Pressure, psi 2000

1500

1000
ps
Well Stimulation

500
1 10 100 1000 10000
Distance from center of wellbore, ft

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Skin and Pressure Drop

0.00708 k h
s ps
qB 
k = md
h = ft
Well Stimulation

q = STB/D
B = bbl/STB
ps = psi
 = cp

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Skin and Pressure Drop

141.2qB
ps  s
kh
Well Stimulation

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Skin Factor and Properties of the Altered Zone

k  ra 
s 
 1
ln
  

a
k  w 
r
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Skin Factor and Properties of the Altered Zone

k
ka 
s
1
ln
ra rw 
The skin factor may be calculated from the properties of the altered zone.
If ka < k (damage), skin is positive.
If ka > k (stimulation), skin is negative.
If ka = k, skin is 0.
Well Stimulation

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Effective Wellbore Radius

rwa 
s ln
r  
w 
rwa rw e s
Well Stimulation

•If the permeability in the altered zone ka is much larger than the formation
permeability k, then the wellbore will act like a well having an apparent
wellbore radius rwa .
•The apparent wellbore radius may be calculated from the actual wellbore
radius and the skin factor.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Minimum Skin Factor

re 
smin ln 
rw 
The minimum skin factor possible (most negative skin factor) would occur when
Well Stimulation

the apparent wellbore radius rwa is equal to the drainage radius re of the well.

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Geometric Skin - Converging Flow to Perforations

When a cased wellbore is perforated, the fluid must converge to

one of the perforations to enter the wellbore. If the shot spacing is
too large, this converging flow results in a positive apparent skin
Well Stimulation

factor. This effect increases as the vertical permeability

decreases, and decreases as the shot density increases.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Geometric Skin - Partial Penetration

hp

A well is completed through only a portion of the net pay

Well Stimulation

interval, the fluid must converge to flow through a smaller

completed interval. This converging flow also results in a
positive apparent skin factor

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Partial Penetration

h
s  t sd s p
hp

h1 Where : Ht =pay thickness ft

hp=perforated thickness

ht h1=height to top of perforations

hp Kv=Vertical permeability (md)
Well Stimulation

Kh=Horizontal permeability(md)
Rd=dimensionless radius

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Partial Penetration Apparent Skin Factor

h1D h1 ht 1
A
h1D h pD 4
h pD h p ht
1
1 B
r kv 2 h1D 3h pD 4
rD  w  
ht  
kh 
Well Stimulation

1   h 1 
1 A 1 2
s p  1ln  ln  
pD

h  2r    
 pD  D h 2 h pD B 1
pD
 
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Geometric Skin - Deviated Wellbore

s sd s
h
 h sec 

When a well penetrates the formation at an angle other than

Well Stimulation

90 degrees, there is more surface area in contact with the

formation. This results in a negative apparent skin factor.
This effect decreases as the vertical permeability decreases,
and increases as the angle from the vertical increases.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Geometric Skin - Well With Hydraulic Fracture

Lf

Often to improve productivity in low-permeability formations, or to penetrate

near-wellbore damage or for sand control in higher permeability formations, a
well may be hydraulically fractured.
This creates a high-conductivity path between the wellbore and the reservoir.
If the fracture conductivity is high enough relative to the formation permeability
Well Stimulation

and the length of the fracture, there will be virtually no pressure drop down the
fracture. This distributes the pressure drop due to influx into the wellbore over
a much larger area, resulting in a negative skin factor.

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Skin Factor and Fractured Wells

Lf
rwa 
2
L f 2rwa
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Completion Skin

rw s s p sd sdp
h   rdp 
k R k R 
s dp   ln 
  
L n 
 r 
k 
p   p  dp k d
 
kdp sp- geometric skin due to converging flow to
rdp perforations
rp sd - damage skin due to drilling fluid invasion
sdp - perforation damage skin
k kd
R - permeability of damaged zone around
wellbore, md
kdp - permeability of damaged zone around
perforation tunnels, md
Lp kR - reservoir permeability, md
Lp - length of perforation tunnel, ft
n - number of perforations
Well Stimulation

h - formation thickness, ft
kd rd - radius of damaged zone around wellbore, ft
rdp - radius of damaged zone around perforation
tunnel, ft
rd rp - radius of perforation tunnel, ft
rw - wellbore radius, ft
After McLeod, JPT (Jan. 1983) p. 32.

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Gravel Pack Skin

Sgp = 96 (K/Kgp) h Lg
dp2 n
Cement

Sgp - skin factor due to Darcy flow through

gravel pack
h - net pay thickness,ft
Kgp - permeability of gravel pack gravel,
md
k - reservoir permeability, md
Well Stimulation

Lg - length of flow path through gravel pack,

in
n - number of perforations open
dp – diameter of perforation tunnel, in
Lg

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Productivity Index

q
J
p p wf
Well Stimulation

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Flow Efficiency

J p pwf ps
Ef  actual 
Jideal p p wf

We can express the degree of damage on stimulation with

the flow efficiency.
Well Stimulation

For a well with neither damage nor stimulation, Ef = 1.

For a damaged well, Ef < 1
For a stimulated well, Ef > 1

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Flow Efficiency and Rate

We can use the flow efficiency to calculate the effects

of changes in skin factor on the production rate
corresponding to a given pressure drawdown

E
qnew qold fnew
E fold

qnew = Flow rate after change in skin factor

Well Stimulation

qold = Flow rate before change in skin factor

Efnew = Flow efficiency after change in skin factor
Efold = Flow efficiency before change in skin factor

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Well Stimulation Objectives

Increase the Production Enhancement

productivity
of a well by:

Remove damage near the wellbore

Superimpose a highly conductive structure onto the
formation
Well Stimulation

Increase the effective area of the reservoir in communication

with the wellbore

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Primary Methods of Stimulation

Matrix acidizing Hydraulic fracturing

(acid or proppant)
Well Stimulation

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Hydraulic Fracturing
Well Stimulation

Hydraulic fracturing is a stimulation technique which

consists in fluid injection into the formation at high flow
rates, causing an increase in pressure and a subsequent
formation breaking.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Hydraulic Fracturing

 The breakdown and early growth,

expose new formation area to the
injected fluid.

 The injected fluid leaking off into the

formation starts to increase.

 If the pumping rate is maintained at

a higher rate than the fluid loss rate,
then the fracture must continue to
propagate & grow.
Well Stimulation

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Hydraulic Fracturing
 Once pumping stops, the fracture closes.
 In order to prevent this, it is added propping agent to the injected
fluid to be transported into the fracture.
 When pumping stops and the fluids flows back from the well, the
propping agent remains in place to keep the fracture opened.
 A conductive flow path for the increased formation flow area is
created.
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Hydraulic Fracturing Objectives

Production Enhancement through:

Clearing Skip damaged area around the

wellbore.
Productivity increase is attached to decrease
the high velocities at the near-wellbore area due
to drawdown
Asphaltene deposition prevention.
Natural fractures connection
Well Stimulation

Scale deposition and H2S prevention: Time

released chemicals.
Water conning retardation

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Impact on Performance

Hydraulics fractures can be classified according

to one of three models:

 infinite conductivity model

– assuming no pressure loss in the fracture
 uniform flux model
– assumes a slight pressure gradient in the fracture
 finite conductivity model
– assumes constant and limited permeability in the
fracture from proppant crushing or poor proppant
Well Stimulation

distribution.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Effective wellbore radius

The fracture case can be

approximated by an equivalent
rww wellbore having the same area
rww’’ as the fracture, and the radius
of this wellbore is r w ’
Well Stimulation

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Hydraulic Fracturing Objectives

Production from Darcy’ s Law (radial flow)

7.08x103 kh( pavg pwf )

Q
o 
ln 0.75 s 
0. 472re / rw 
Q: Stabilized production rate for oil BPD
k: Effective formation permeability, mD
h: Formation thickness, ft
pavg : Average reservoir pressure, psi
pwf : Bottomhole flowing pressure, psi
: Fluid viscosity, cp
Well Stimulation

o: Oil formation volume factor,

re : Drainage radius, ft
rw : Wellbore radius, ft
s: Skin effect

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Hydraulic Fracturing Objectives

Production increase

Q f ln
r /r 
PI   e w
Qi lnre / rw 

Qf = Stabilized production after frac

Qi = Stabilized production before frac
Well Stimulation

re = Drainage radius
rw = Wellbore radius
rw’ = Effective wellbore radius

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Hydraulic Fracturing Objectives

Production increase calculations assumptions

Steady state production

Same drawdown for each production rate
Single phase flow
No skin damage for production before fracture
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Hydraulic Fracturing Types

High permeability formations (k>20 mD)

Damage bypass.
Fracture length becomes
less important.
Geometry: Short and wide
fractures.
Well Stimulation

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Hydraulic Fracturing Types

Low permeability formations (k<1

(k<1 mD)

Put more reservoir area in

contact with the well.
Fracture length controls
production increase
Geometry: Long and
Well Stimulation

narrow fractures

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Hydraulic Fracturing Objectives

Effect over production

Production History
1044
10
Oil Flowrate

With fracture
10
103
(bpd)

102
10
Well Stimulation

Without fracture

101
0 10
10 20
20 30
Time (months)
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Hydraulic Fracturing Objectives

Effect over production

Production Productivity Index
performance
Bottomhole flowing pressure (psia)

12000 8.0 bpd/psi

10000 1/4”
1/4”

3/8”
3/8”

7/16”
7/16”
8000

Productivity Index
Well Stimulation

6000
0.58 bpd/psi

4000
0 1000 2000 3000 4000 5000 6000

Oil flow rate (bpd)

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Hydraulic Fracturing Design

Proper treatment design is tied to several

disciplines:

Production engineering
Rock Mechanics
Fluid Mechanics
Selection of optimum materials
Operations
Well Stimulation

It is a multidisciplinary approach with a multitude of variables

involved, with some uncertainty in the absolute values of these
variables: Engineering judgment is very important.

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Fracture Design Base Sequence

1. Identification of
elastic constants,
effective stress
stress field orientation.
2. Fluid selection system.
3. Proppant selection
4. Fracture propagation model on the basis
of in-situ stress and laboratory tests
Well Stimulation

calibration treatments
log analysis (e.g. stress profile, gamma ray, sonic logs).

5. Tubing stress analysis

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracture Design Base Sequence

6. Determine
fracture penetration
fracture conductivity
7. Determine
injection rates
fluids and proppant volumes required and fracture conductivity
obtained.
Well Stimulation

8. Determine the production rate and cumulative recovery over a

selected period of time for a specific propped penetration
9. Calculate the NPV

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Fracture Design - Input data

Geomechanical Reservoir

•Poisson's Ratio (Logs, Core Tests) •Porosity (logs, cores)

•Young’s Modulus (Logs, Core Tests) •Compressibility (Test, Calculations)
•Fracture Toughness (Tests, History •Net Pay (Logs, Cores)
Match) •Permeability (Cores, Tests)
•Minimum Horizontal Stress •Fluid Viscosity (Lab Tests, PVT)
(Minifrac, Calculations) •Fluid Compressibility (Lab Test, PVT)
•Stress Contrasts (Logs, Core Tests)

Fracture Fluids Completion

•Rheology (Lab Tests) •Completion Schematic.

Well Stimulation

•Tubular and Connections Ratings

•Density (Lab Tests)
•Completion components specifications
•Filter Cake (Lab Tests)
•Filtrate Viscosity (Lab Tests)

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Rock Mechanics in Hydraulic Fracturing

In situ stresses
Direction of the
The minimum in-situ stress is the vertical stress
dominant parameter
fracture geometry.
controlling V Direction of the
maximum
The minimum in situ stress is Direction of the horizontal
generally horizontal. minimum stress
Hydraulic fractures are always
horizontal Hmax.
perpendicular to the minimum stress, stress
except in some complex cases. Hmin
Well Stimulation

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Rock Mechanics in Hydraulic Fracturing

Stresses
Stresses field
field and
and wellbore
wellbore orientation
orientation
Well Stimulation

Schematic of the orientation of hydraulic Orientation of hydraulic fractures

fractures for two horizontal wells between the minimum and maximum
principal stresses

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Rock
Rock Mechanics - Models
Mechanics-Models
Geometry models

2D Model

•The fracture height estimated remains constant for the simulation.

• The fracture length grows from a line source of perforations, and all
layers have the same penetration.
•The simulation can be approximated by the average modulus of all
the layers.

•KGD (De Klerk-Geertsma) the fracture height is relatively large

compared with its length.
Well Stimulation

•PKN (Perkins-Kern) the fracture length is the much large

compared with its height.

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Rock
Rock Mechanics - Models
Mechanics-Models
Geometry models

Pseudo 3D model

•Pseudo three-dimensional model is the same as the PKN model – that is,
vertical planes deform independently.
•The height of the fracture depends on the position along the fracture and
the time.
•A vertical fracture will grow in a layered medium as a function of the
layer properties
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Rock Mechanics - Models

2D
2D models
models as
as aa function of 
function of P
P
Well Stimulation

L: Fracture half length ; W: Fracture width; C: Leak off coefficient H:heigh

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Fracturing fluids

Sufficient Viscosity to Create Fracture

Low Friction Pressure to Minimize Equipment Horsepower

on Location

Sufficient Leakoff Control to Efficiently Create and

Propagate Fracture

Sufficient Viscosity to Transport Proppant

Well Stimulation

Must lose Viscosity (or “break”) after placement to

facilitate production

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing fluids
100

80
Water
60
% Treatments

Oil

40

20
Well Stimulation

49 53 57 61 65 69 73 77 81 85 89 93 97

Year

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Fracturing fluids

Oil fluids

Non-damaging to clays
Compatible with formation fluids
More expensive & operationally difficult to handle. Only
used in extremely water sensitive formations.

Water fluids

Safe
Well Stimulation

Available
Economical
Controlled break times
Broad temperature range

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids

Viscosity

Newtonian Fluid
Viscosity = Stress / Shear Rate

Non-Newtonian Fluid
Non-
(1-n)
Viscosity = k/
Power law Model of Viscosity used in Fracture
Simulations
= Shear rate
Well Stimulation

k = Consistency Index.
n = Fluid Behaviour index

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Fracturing fluids

Fracturing Fluids Chemicals

Polymers
Cross linkers
pH Control
Gel Breakers
Clay Control
Well Stimulation

Surfactants
Fluid loss Additives
Biocides

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing fluids - Polymers

Base Gel Hydrated Polymer

Dry polymer

+ H2O
Well Stimulation

Dry polymer is added to water to swell (hydrate),

forming a viscous gel fluid.

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Fracturing fluids - High Viscosity Guar

Viscosity of Linear Guar

Fluids vs. Temperature

Can be used in
brines.
6-8 % residue.
Easy to crosslink.
40 Lb/Mgal 36 cp
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Hydroxypropyl Guar (HPG)

Can be used in brines.

1-2 % residue.
Good crosslink control
Good thermal stability-High
temperature wells

20 lb/Mgal 30 lb/Mgal 40 lb/Mgal

Well Stimulation

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Fracturing Fluids CarboxymethylhydroxypropylGuar

(CMHPG)

Can be used in brines.

1-2 % residue.
Good crosslink control.
Excellent thermal stability.
40 lb/Mgal 28 cp
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids - Hydroxyethyl Cellulose (HEC)

Can be used in brines.

Residue Free.
Not Crosslinkable.
Limited Thermal Stability.
40 lb/Mgal 46 cP
Well Stimulation

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Fracturing Fluids – Xanthan (XC)

Bio-polymer and behaves like a power fluid

Can be used in brines.
3% Residue.
Difficult to break control
Easy to Crosslink.
Good Thermal stability.
40 lb/Mgal 20 cp
More expensive than gaur but provide better
Well Stimulation

suspension

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – LGC

Liquid Gel Concentrates ( LGC )

A dispersion of non-swelling polymer stabilized in

a hydrocarbon base
50 % polymer + 50 % diesel
Well Stimulation

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Fracturing Fluids – Crosslinking agent

Metal Ions used to cross link

polymers
Linking the –OH at high Ph
Borate
 Zirconium Crosslink Reaction

 Titanium
Well Stimulation

 Antimony
 Aluminium

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Crosslinked Frac fluids

Polymer Crosslinker Max. Temp ºF

CMHPG Zr 275
CMHPG Zr 400
G,HPG B 350

G,HPG B 300
G B 200
G Zr 275
Well Stimulation

G B+Zr 300
HPG Ti 300

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Fracturing Fluids – Gel breakers

•Relatively high viscosity fluids are used to transport proppant

into the fracture.

•Leaving a high-viscosity fluid in the fracture would reduce the

permeability of the proppant pack to oil and gas, limiting the
effectiveness of the fracture treatment.

•Gel breakers are used to reduce the viscosity of the fluid

intermingled with the proppant.

•Breakers reduce viscosity by cleaving the polymer into small-

molecular weight fragments.

•The most widely used fracturing fluid breakers are oxidizers

Well Stimulation

and enzymes.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Gel breakers

Enzymes- Hemicellulase
Soluble / 60 -140 °F / pH 4 -8
Encapsulated / 75 - 175 °F / pH 4 –9
They begin to degrade the polymer on mixing at
ambient temperatures.
Oxidizers (Soluble and encapsulated)
Ammonium peroxydisulfate
Calcium peroxide
Sodium bromate
Well Stimulation

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Fracturing Fluids – Gel breakers

Selection
Selection of Breaker
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – pH control

Importance of pH control
pH Control  Polymer Hydration rate.
 Crosslinking rate.
Neutral
 Gel Stability
0 7 14
 Gel Break rate.

Acid Basic
Well Stimulation

pH Log (H ) 
High pH (12) for Borate crosslinked fluids.

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Fracturing Fluids – pH control

pH Control Chemicals

Acid
 Sulphamic Acid
 Acetic Acid (CH3COOH)
 Fumaric Acid, Organic acid.
 HCL

Base
 Sodium bicarbonate.
Well Stimulation

 Sodium carbonate
 Liquid carbonate
 Solution 25% NaOH

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Surfactants

A surface active agent that at low concentration adsorbs

at interface between two immiscible substances.
Properties of Surfactants
Reduce interfacial tension and capillary pressure
Alter wetting properties of surfaces-Formation
conditioning agents
 Stabilize or break emulsions
Stabilize Foams and prevent sludge

Surfactants molecules have two distinct parts.

Well Stimulation

Water Soluble Head

Oil Soluble Tail

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Fracturing Fluids – Surfactants

Surfactants migrate to interface between solids, liquid

and gases

Water Oil
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Clay swelling control

Inorganic Salts
KCL, NACL, CaCL2, NH4CL
Cationic Polymers-Quaternary amines
Well Stimulation

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Fracturing Fluids – Fluid loss

Fluid Loss
Fluid loss to the formation during a fracturing treatment is a filtration
process that is controlled by a number of parameters, including fluid
composition, flow rate and pressure, and reservoir properties such as
permeability, pressure, fluid saturation, pore size and the presence of
micro fractures.

Fluid Loss Control

Filtrate viscosity and relative permeability.
Wall-building fluids: Filter Cake.
(polymer and/or fluid-loss additives, silica, starch, soaps, waxes)
Multi Phase Flow viscosity
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Fluid loss

Fluid Loss

Fracturing fluid

Gel Filter Cake

Zone Invaded by water
Well Stimulation

Uncontaminated Formation

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Fracturing Fluids – Polymer damage

Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Low polymer/High T

PrimeFRAC

Low Polymer High

Temperature
Fracturing Fluid

Broad field water chemistry compatibility

No pre-treatment required
Well Stimulation

Thermally delayed crosslink easily controlled

Low buffered crosslink pH
Controllable viscosity reduction with breakers

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Fracturing Fluids – Low Polymer/High T

PrimeFRAC
Stable Low Polymer Rheology Over a Broad Temperature Range
(30 ppt polymer, Fann50 B5Bob, API Testing)

800

700
Viscosity @ 100 sec- 1 (cp)

600
500

400 350°F

300 300°F

200
Well Stimulation

YF850HT -
300°F
100 250°F
0
0 50 100 150 200
Time (minutes)

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracturing Fluids – Viscoelastic

Viscoelastic Surfactant Based Systems (VES)

First polymer free, water-based ClearFRAC Principle

fracturing fluid
Commercialized in 1997
Three VES systems currently
available

Viscoelastic Surfactant
+ NH4Cl
e.g., KCl
Well Stimulation

Electrolyte MgCl 2
+ + + +
+ + + + +
+ + + + +
+ + + + + + + + +
+ + + + +

=
+
+ + + + +

+
+
+ + + + + + + +

+
+
+ + + + + + +
+ + + + + + + +
+ +
+ + +

+
+ +

+
+ + + + + +
+ + + + + + + +
+ + + + + +
+ + +
+ +
+ + + + + + + +
+ + + + + +
+ + + + + +
+

+ + + +

Rod Shaped Micelles +

+ + + + + +

+
+ + + + + + + +

+
+
+ + + + +
+ + +
+ +

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Fracturing Fluids – Viscoelastic

Rod Shaped Wormlike

Well Stimulation

Micellar Structure
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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Well Stimulation
Fracturing Fluids – Selection

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Proppant selection-Fracture conductivity

Fracture conductivity

Placing the appropriate amount and type of proppant in the

fracture is critical to the success of a hydraulic fracturing
treatment.

It is defined as the relative ease with which the injected

fracture fluids and proppants flow to the wellbore fracture.
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Proppant selection – Fracture Conductivity

Fracture Conductivity

Cf = kf x wf
Fracture permeability x Fracture width
Fracture with
proppant
Well Stimulation

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Proppant selection – Fracture Conductivity

Factors affecting conductivity

Fracture length
Fracture width
Proppant concentration-Physical properties
Proppant size and type
Proppant transport
Closure stress on proppant bed
Well Stimulation

Bottomhole temperature
Treatment fluid effects
Movement of formation fines

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Proppant selection – Fracture Conductivity

Closure stress

The stress applied to the proppant bed when the

fracture has closed.

Closure pressure
The pressure above reservoir pressure which a fracture
Well Stimulation

will open or close.

This pressure is equal to the least principal stress.

©2005 Abalt Solutions Limited. All rights reserved

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Proppants
They are used to hold the walls of fracture apart and
create a conductive path to the wellbore after pumping
has stopped and fracturing fluid leaked-off.

Sand
Premium sands come from Illinois, Minnesota and
Wisconsin. These sands greatly exceed API standards.
They are commonly known as:

 Northern sand;
 White sand;
 Ottawa sand;
 Jordan sand;
 St. Peters sand;
Well Stimulation

 Wonewoc sand.
The specific gravity of sand is approximately 2.65.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Proppants

Resin Coated Sand

 Resin coatings may be applied to improve proppant
strength.
 The resin coating on the proppant is usually cured during
the manufacturing process to form a non melting, inert
film.
 When the grains crush the resin coating helps
encapsulate the crushed portions of the grains and
prevents them from migrating and plugging the flow
channel.
 Resin coated sands usually have a specific gravity of
Well Stimulation

about 2.55.

©2005 Abalt Solutions Limited. All rights reserved

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Types of Proppants

Intermediate Strength Proppants

 Intermediate strength proppants (ISP) are fused ceramic
proppants that have a specific gravity between 2.7 and
3.3.
 ISP’s are mainly used for closure stress ranges between
5,000 psi and 10,000 psi.

High Strength Proppants

 Sintered bauxite and zirconium oxide are high strength
propping agents with a specific gravity of about 3.4 or
Well Stimulation

higher.
 Generally limited to wells with very high closure stresses.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Proppant selection – Fracture Conductivity

Effect of Proppant Type
20/40, 200 °F, 2.0 lb/ft²
12000

At 7000 psi, Proppant Type

Cond = 5336 md*ft
Conductivity (md*ft)

10000 H Brady
H Ottawa
8000
H CARBOPROP/INTERPROP
S SINTERED BAUXITE

6000

4000
Well Stimulation

2000

0
00:00 3000 6000 9000 12000 15000

Stress (psi)

©2005 Abalt Solutions Limited. All rights reserved

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Proppant selection – Fracture Conductivity

Proppant type vs. Closure stress

6
Sand
Resin Coated Sand 8
Inter-Strength Ceramic 10
Inter-Strength Bauxite 15
High-Strength Bauxite 20
Well Stimulation

0 5 10 15 20
Closure Stress psi x 1000

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Conductivity considerations
Dimensionless Conductivity Ratio - Cinco
Cinco--Ley
Quantity Value Characteristic
kf 10 D Poor
Fracture
Conductivity 100 D Good

kf w 1000 D Excellent


k f.W 100 md-ft Poor

FCD 1000 md-ft Good

k xf FcD
10000 md-ft
<10
Excellent
Poor
10-50 Good
Formation >50 Excellent
conductivity
Well Stimulation

FCD: Dimensionless conductivity ratio

kf: Fracture permeability (mD)
k: Formation permeability (mD)
w: Fracture width (ft)
Xf : Fracture half length (ft)

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Conductivity considerations

High permeability Low permeability formations

formations (k>20 mD) (k<1
(k<1 mD)
Put more reservoir area in
Damage bypass.
contact with the well.
Fracture length becomes
Fracture length controls
less important.
production increase
Geometry: Short and wide
Geometry: Long and
fractures.
narrow fractures
Moderate permeability formations
Well Stimulation

(1 mD < k< 15 mD)

ECONOMIC ANALYSIS

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Economic considerations
1)
1) Fluid
Fluid cost
cost 2) Proppant
Proppant cost
cost

Including, Including,
• Fracture fluid, • Proppant,
• Fracture additives, • Proppant transportation to
• Mixing and blending location and storage,
charges, • Proppant pumping charges.
• Transportation, storage
and disposal charges.
4) Other fixed costs
3)
3) Hydraulic
Hydraulic horsepower
horsepower Including,
(hhp)
(hhp) • Mobilization,
• Personnel,
Well Stimulation

cost = ($/hhp)x((injection • Well preparation (workover

rate x surface treating rig, etc.)
pressure/40.8) +standby hhp) • Cleanup costs (coiled tubing,
disposal, etc.)

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Proppant selection – Fracture Conductivity

Other factors to take into account for design

Quality of the cement job for

zonal isolation.
Size and conditions of wellbore
tubulars.
Perforations
Wellbore deviation
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Tubing stress analysis

Completion integrity during the
Hydraulic Fracture Treatment

•Define potential completion risks and

Identify the required operational
considerations to meet the specified safety
factors for burst, tension and collapse
Well Stimulation

under the load conditions.

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Design

Evolution of Proppant Distribution

During Pumping

1 lb/gal Pad
c
Well Stimulation

The first proppant stage is injected

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Design

Evolution of Proppant Distribution

During Pumping

2 lb/gal 11 lb/gal
lb/gal
33 lb/gal
lb/gal to
to Concentrated Pad
Pad
3 lb/gal to 3 lb/gal
c
Well Stimulation

At intermediate time

©2005 Abalt Solutions Limited. All rights reserved

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Design

Evolution of Proppant Distribution

During Pumping Proppant
Settling

5 44 to
to 55 lb/gal
lb/gal 2 to
lb/gal
lb/gal 1 lb/gal
55 lb/gal
lb/gal
c concentrated
concentrated
3 to 5 lb/gal to
to 55 lb/gal
lb/gal
Well Stimulation

At End of Pumping

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Design
The pad volume determines how much fracture penetration can be
achieved before proppant reaches the tip and stops penetration in
the pay zone.

Too much pad can cause that fracture tip continues to propagate
after pumping stops, leaving a large umpropped region near the
fracture tip. An afterflow can occur in the fracture, carrying proppant
toward the tip and living a poor final proppant distribution.

The ideal schedule is one where the pad depletes and proppant
reaches the fracture tip just at the desired fracture penetration is
achieved and also just as pumping stops.
Well Stimulation

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Design
Tip Screen-
Screen-out (TSO)
Screen-out

The tip screen-out fracturing technique applies hydraulic fracturing

technology to create a wide, short, fracture that yields high
production rates with reduced pressure drops. It can be a highly
effective technique in stimulating maximum production from weak
formations.

A TSO is designed to cause proppant to pack at an specific location

because of width restriction, pad depletion or slurry dehydration.

Once packing occurs, further fracture propagation ceases at this

point, usually at the tip. Continued injection increases the hydraulic
fracture width and final conductivity
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Job execution

Strategic Locations
on a Pressure Response Curve

11
2 55
Pressure
Pressure
3 1- Formation Breakdown
44
2- Propagation 88
Pr essure
Bottomhole Pressure

Rate
Inje ction Rate
Injection
Injection Rate
Rate 3- Instantaneous Shut-In

Injection
4- Closure Pressure From Fall-Off
Bottomhole

Inje ction
Injection

Injection
Injection
Second
Well Stimulation

cond
Cycle
Cycle

Cycle
Cycle
FFirst
irst

7
Se

Shut-in
Shut-in
Flowback

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Strategic Locations on a Pressure Response Curve

Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Job execution
Treatment schedule-Example
Well Stimulation

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Job execution
Simulation results - Example
Well Stimulation

Fcd = 0.9
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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Job execution

Operation Layout
Well Stimulation

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Job execution

Additives/proppant deposits
Blender
Well Stimulation

Manifold
(inlet/outlet)

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Job execution

Pump Truck
Well Stimulation

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Job execution

Equipment

Reference treatment
Well Stimulation

Qmax: 60 bbl/min
hhp used: 17600
hhp Available: 20000
Volume: 3.2 million lb proppant

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Well Stimulation
Job execution

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Alternative technology – wellbore communication

MLD (Minilateral Lateral Drilling). The drilling of laterals

tunnels around the wellbore, through the casing and cement into
the formation, creating a draining architecture (fish bone
structure) that will have a direct impact over the flow
performance in the well, depending on the number of tunnels
created.

Formation Penetration (MLD tool): Up to 2 mt (6.6 ft), tunnels.

Description (MLD Tool): Downhole tool system designed to

produce communication tunnels, radially from an existing
wellbore into reservoir rock, for up to 2 meters in length. The tool
drills one tunnel at a time, each requiring 10 to 20 minutes to
complete, and is capable of making multiple tunnels during a
Well Stimulation

single run.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Alternative technology – wellbore communication

Tool sizes: The MLD tool is available for casing sizes of 4 1/2", 5",
5 1/2", 6 5/8", 7" , 8 5/8", 9 5/8".

Drilling Tunnels: The creation of the tunnels will be governed by

factors such as well depth and rock Lithology. The completion fluid
will also affect the number of tunnels that can be completed on a
single trip – normally the tool will be capable of 4 to 8 tunnels per
run.

Work over fluids: A selection of the work over fluid should be made
based on its compatibility with the formation fluids and mineralogy
to reduce the risk of formation damage during the operation. Fluids
such as light oil would often be a good choice.
Well Stimulation

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Introduction to Hydrocarbon Exploitation

Acidizing Applications

Pratap Thimaiah

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Overview

 Matrix stimulation is injecting an acid/solvent

at below the fracturing pressure of the
formation
– to dissolve/disperse materials that impair well
production in sandstone reservoirs
– to create new, unimpaired flow channels in
carbonate reservoirs
Well Stimulation

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Sandstone vs. Carbonate Acidizing

 Sandstone:
– A small fraction of the matrix is soluble
– Relatively slow reacting acid dissolves the
permeability damaging minerals
Wellbore

Damaged
zone
 Carbonate:
– A large fraction of the matrix is soluble (>50%)
– Rapid reacting acid creates new flow paths by
dissolving formation rock
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Key Issues

 Successful matrix treatments require

– Correct choice of fluid to attack damage
– Uniform placement of treating fluid

Improper placement
increases heterogeneity
Well Stimulation

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Candidate Selection

 “Good Wells Make the Best Candidates for

Well Stimulation” - Al Jennings

 Candidate Selection (Recognition) is the

process of identifying and selecting wells for
treatment which have the capacity for higher
production and better economic return.
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Candidate Selection Process

– Review numerous wells.

– Review of well logs/records, reservoir characteristics
and information on the completion/previous
workovers.
– Map the productivity of each well.
– Establish reasonable upper production potential for
fracturing and matrix stimulation techniques.
– Evaluate potential mechanical problems.
Well Stimulation

– Focus on wells with the highest reward and lowest

risk.

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Data Sources
 Production History  Logs
– Oil/Gas/Water – SP, Gamma, Porosity,
production Production logs
– Decline curve – Reservoir
characteristics
– Drive mechanism
 Hydrocarbon
 Homogeneous/Laminat
1000
ed
 Thickness
 WOC/GOC
Oil Rate , BOPD

100

offset well
Well Stimulation

10 Water oil contact

Gas-oil contact
1
0 20000 40000 60000 80000 100000 120000
Cumulative Oil, Bbls

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Data Sources
 Workovers  Drilling records
 Well tests – Type of mud
– Kh – Losses
– Skin
 Completion
– Pres Build up test
– Openhole/Cased/Fractur
ed
– Directional survey
– Tubing/Casing
USIT
Callipers
Well Stimulation

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Establish Production Potential

Re
se
rv o
ir
Pressure

Tubing
Well Stimulation

Existing Gap Potential

productio production
n
Flow Rate

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Introduction to Hydrocarbon Exploitation

Matrix Acidizing

Formation Damage Characterization

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Near-wellbore damage limits production

Inorganic
scales

Damage
reduces oil
flow
Drilling damage
Paraffin/Asphaltene
deposits
Wettabilit
Well Stimulation

y change Migrating clays/silts

Emulsio Swelling clays

n
damage

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Formation Damage Characterization

 Fines Migration  Induced Particles

 Swelling Clays – Solids
 Scale Deposits – LCM/Kill Fluids
– Precipitates
 Organic Deposits
– Paraffins  Oil Based Mud
– Asphaltenes  Emulsion Block
 Mixed Deposits  Wettability Changes
Well Stimulation

 Water Block
 Bacteria

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Silt and Clays = Fines

 Origins
– Indigenous - clays, silica fines
– Drilling fluid invasion
 Potential problems
– Fines migration causes plugging
– Clay swelling
 High production rates can entrain particles and
cause bridging.
 Indicators of particle migration
– Produced water may be turbid
Well Stimulation

– Production decline increases with increasing flow

rate.
– Clays and silica fines are insoluble in HCl.

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Scale
 Inorganic mineral deposits.
 Formed due to supersaturation at wellbore
conditions or commingling of incompatible fluids.
 Form in the plumbing system of the well, in the
perforations or in the near-wellbore region.
 E.g.
– Calcium carbonate/sulfate
– Barium sulfate
– Iron carbonate/oxide/sulphide
Well Stimulation

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Paraffins
 Linear or branched-chain saturated aliphatic
hydrocarbons
– C20 H42 to C60 H122

 Moderate molecular weights

– Sharp melting points
– Needle like crystals - granular particles
– Soft to hard, brittle solids
– Limited solubility in crude oils
– Soluble in:
Well Stimulation

 Distillates
 Aromatics
 Carbon Tetrachloride and Carbon Disulfide
 Burns with a clean flame

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Asphaltene Deposits

 Aggregate of condensed polycyclic aromatic ring

 Types of asphaltene deposits
– Hard coal-like deposits
– Sludges and rigid film emulsions
 Colloidally dispersed in crude oils
 Burns with black sooty flame
Well Stimulation

Asphaltene Deposits on Calcite

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Drilling Damage
 Filter cake should prevent
extensive damage to
formation during drilling
 Low permeability (~ 0.001md) Filter cake Formation
filter cake may be damaging
during production
– formation permeability may
be impaired
– potential plugging of
screen/ gravel pack
 Openhole completions do not
have perforations or fractures
Well Stimulation

to bypass any damage

 Filter cake removal maybe a
necessity!
RDF (STARDRILL) Filter Cake

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Emulsion

 A stable dispersion of two immiscible fluids.

 Formed by invasion of filtrates into all zones
or co-mixing of oil-based filtrates with
formation brines.
 Stabilized by fines and surfactants
 Treatment: Mutual Solvents, Clean Sweep
Well Stimulation

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Water Block
 Reduction in relative
permeability to oil due to
increased water saturation in
the near wellbore region.
 Favored by pore-lining clay
minerals (Illite) 1 1

 Treatment Water Wet

Oil Wet
– Reduction of interfacial Kro
Kro Krw
tension using Krw

surfactants/alcohol's in acid
carrier
Well Stimulation

0
0 Swc 1-Sor 1
Sw

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Introduction to Hydrocarbon Exploitation

Sandstone Acidizing

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Sandstone Acidizing

Primary design considerations

Fluid selection – acid type concentration and

volume
Wellbore and Completion characteristics
Injection schedule – planned rate schedule and
sequence of injected fluids.
Acid coverage and diversion (placement
technique) – special steps taken to improve acid
contact with the formation.
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing

Methodology
Identify the damage mechanism
Determine the mineralogy
Know the well parameters
Know the well fluids
Select the specific system
Apply the treatment
Well Stimulation

Follow the results

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Sandstone Acidizing

Sandstone's - Mineralogy

Secondary
Cement Quartz
(Carbonate Quartz)
Clays *Feldspars
(Pore lining
i.e., illite)
Clays *Chert
(Pore filling
i.e., Kaolinite) Remaining Pore Space
*Mica
Well Stimulation

*Porosity-Filling
Minerals *Mud Acid Soluble/Sensitive

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing

Well parameters – Well fluids

Type of well (gas, multiphase)..
Bottomhole static temperature
Formation permeability
It is important to know
the compatibility between
the produced fluids and the
acid (emulsion/sludge test). K 5 mD is
Well Stimulation

Also the fluids used to drill required

or complete the well.

©2005 Abalt Solutions Limited. All rights reserved

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Sandstone Acidizing

Sandstones acids
The most common acids are Hydrochloric acid,
HCl, and Hydrofluoric Acid, HF.
HCl is used to dissolve carbonate minerals.
Mud Acid (Hydrofluoric/ Hydrochloric) is used
to attack silicate minerals such as clays and
feldspars.
The regular mud acid is 12%HCl –3%HF
Well Stimulation

Some weak organic acid are used in special

applications such high temperature wells.

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing – HF reactions

HF reactions
Due to mineralogical differences, HF chemical
reactions in sandstones acidizing are very
complex.
Carbonate acidizing involves only one reaction:
the reaction of acid with carbonate minerals to
form calcium salts, water and carbon dioxide .
Well Stimulation

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Sandstone Acidizing – HF reactions

Primary reactions dissolves skin damage

as assumed.

1st Reac..
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing – HF reactions

Metals ions associated with

Primary Reaction: the clay

HF + M-Al-Si  AlFx + HSiF5 + M+

Aluminium Silicates
Aluminium Fluorides Silicon Fluorides

This is the reaction that removes damage and improves

Well Stimulation

permeability

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Sandstone Acidizing – HF reactions

Secondary precipitation decreases formation

permeability. Silicon fluorides form when acids are
incompatible with mineralogy.

2nd Reac..
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Secondary and Tertiary Reactions

Aluminium Fluorides
Secondary Reaction:
HSiF5 + M-Al-Si + H+  Silica gel + H2O + AlF x +M

Silicon Fluorides Aluminium Silicates Metals ions

(M: Metals ions associated with associated with the
the clay) clay

This is the reaction of the silicon fluorides with clays and feldspar.
The silicon is precipitated in a silica gel.
During this reaction a secondary precipitation can occur, decreasing the
Well Stimulation

treatment efficiency or the treatment to fail.

Sodium and potassium present in the formation can form gelatinous
solids which can cause severe plugging problems.

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Sandstone Acidizing – HF reactions

Acid continues to react causing aluminium to precipitate.

Aluminium-silicate scale clogs wellbore.
Well Stimulation

Scales in a pipe.
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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing – HF reactions

Tertiary Reaction:
AlFx + mineral +  AlFy + silica gel

In this reaction the aluminium fluorides react until all remaining

acid is consumed
The resulting high aluminium concentration and low acid
concentration can lead to aluminium precipitation within the
formation or scaling within the wellbore. This aluminium-silicate
Well Stimulation

scaling can occur days or months following an HF treatment.

©2005 Abalt Solutions Limited. All rights reserved

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Sandstone Acidizing - design

Sandstone's - Mineralogy
Illite

Can cause fines migration

problems; is ion
exchanging. Contains
potassium which can cause
fluosilicate precipitation
from spent HF.
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing - design

Sandstone's - Mineralogy
Mixed-layer clay

Is ion exchanging, swells in

fresh water, and frequently
contains potassium which
can cause fluosilicate
precipitation from spent HF.
Well Stimulation

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Sandstone Acidizing - design

Sandstone's - Mineralogy
Chlorite Potassium feldspar
Is ion exchanging and is Fluosilicate precipitation can
unstable in HCl create major problems
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing – design

Treatment stages – Pre-flush conditions by:

Dissolving carbonates
Pushing fluids out of the way
Preparing formation through ion exchange
Well Stimulation

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Sandstone Acidizing – design

Treatment stages – Main Treatment

 Dissolves skin damage to improve formation

permeability
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing – design

Treatment stages – Over flush

 Secondary precipitation near wellbore by

driving out fluids
Well Stimulation

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Sandstone Acidizing – design

Treatment stages – Displacement

 Maximizing by forcing fluids from pipe

Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sandstone Acidizing Fluid Stages

Mud acid removes alumina-silicate formation damage

Brine preflush displaces brines containing incompatible
Well Stimulation

cations away from the wellbore.

HCl (or organic acid) preflush removes CaCO3 from matrix
to prevent the precipitation of CaF2.
Overflush displaces spent acid away from the critical matrix.
©2005 Abalt Solutions Limited. All rights reserved

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Acidizing Additives

 Inhibitors
 Surfactants
 Foaming Agents
 Mutual Solvents
 Anti-sludge Agents
 Non-Emulsifiers
 Iron Control
 Friction Reducers
 Clay Control
Well Stimulation

 Specialty Additives

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Guidelines for Acid Placement

Several placement techniques are available

Mechanical methods
Bridging agents and diverters
selective fluids
Well Stimulation

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Fluid Placement - Diversion

Successful acid matrix treatments, require
the acid to be placed so that all potentially
productive intervals accept a sufficient
quantity of the total acid volume.
To achieve uniform damage removal, the
original flow distribution across the
treated interval needs to be altered to
provide generally equal acid distribution.
The methods used to alter this flow
distribution are called diversion methods.
Well Stimulation

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fluid Placement - Diversion

Criteria for selection of a diversion technique

Must provide uniform distribution of treating fluid

Must not cause permanent damage to formation
A rapid and complete cleanup must be possible
Diversion agent must be compatible with the
treating fluid
Must be effective at the applicable treatment
temperature
Well Stimulation

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Fluid Placement -

Mechanical Methods

Ball Sealers

Packers
conventional buoyant
density ball sealer
ball sealer
Well Stimulation

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Mechanical Placement Techniques

Advantages:
Less sensitive to chemical composition of fluid
and temperature.

Disadvantages:
Requires special equipment.

Requires good zonal isolation.

Requires adapted completion (no gravel pack or
Well Stimulation

open hole).

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Diversion

Chemical Methods
Bridging agents (solids) External diverters
Water Soluble
Oil soluble
Viscous plugs Internal diverters
Reactive
Visco-elastic surfactants
Foam
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

External Diverting Agents

 Advantages
– Don’t require rigs or special downhole tools.

 Disadvantages
– Compatibility between diverter and fluids
Solubility
Dispersability
– Careful design required to match rock pore size
distribution.
Well Stimulation

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Water Soluble Diverting Agents

Sodium benzoate:
– C6 H5 COONa + HCl C6H5 COOH +
Na + + Cl - (Benzoic Acid)
 It is dissolved by injection water after acting as
a diverter and results in easy cleanup.
 The benzoic acid is partly soluble in the treating
fluid and can be at used up to 5 Darcy's
permeability. It is designed for treating
injection wells with up to 150F bottom hole
Well Stimulation

injection temperature

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Internal Chemical Diverters

 Problem
– Flow paths that exist or are created behind the
sandface, or behind screens cannot be plugged
with external diverters.
 Solution
– Reactive diverting agents (U102)
– OilSEEKER
– Foam MAT Diversion Service
 Benefits
– Improves zonal coverage during matrix
Well Stimulation

stimulation of horizontal and vertical wells

– Improves treatment success and production

©2005 Abalt Solutions Limited. All rights reserved

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OilSEEKER
 OilSEEKER is based on VES
technology.
– Contains no solids,
polymer or nitrogen
– Very easy to mix and
OilSEEKE
pump in the field R
 Selectively plugs the high-water- Mw = 450
saturation zones, causing acid to
enter the high-oil-saturation
zone.
 Compatibility testing must be
performed
 VES diverters have the
significant advantage of
Well Stimulation

leaving no formation
damage creating residue
in the formation.

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

OilSEEKER: Features and Benefits

 Improve acid placement in high water-cut

wells
– Vertical
– Deviated
– Horizontal
 Applicable in oil/gas condensate wells
– Carbonates
– Sandstones
Well Stimulation

 Easy to mix and apply in the field

 Does not require nitrogen

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Foam Diversion Process: Step 1

Damaged Zone

Thief Zone
Well Stimulation

 Clean the near wellbore area using

brine
 Displace oil or condensate
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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Foam Diversion Process: Step 2

Damaged Zone

2 1 Thief Zone
Well Stimulation

 Saturate the near wellbore region with foamer

 Remove damage form the thief zone
 Saturate the rock with foamer to stabilize the foam

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Foam Diversion Process: Step 3

Damaged Zone

2 Thief Zone
1
Well Stimulation

 Foam injection- Inject HCl or brine

containing a foaming agent (F101, F78,
F52.1, or F75N)
– Foam bank is formed in both layers
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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Foam Diversion Process: Step 4

Damaged Zone

2 Thief Zone
1
Well Stimulation

 Shut-in period
– Foam dissipates rapidly in damaged
zone
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Foam Diversion Process: Step 5

Damaged Zone

2 Thief Zone
1
Well Stimulation

 Inject treating fluid containing foamer

– Acid preferentially flows into low perm
layer

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Foaming Agent Selection Guide

 For HCI, Mud Acid and Clay Acid treatments

Permeability 100F to 125F 126F to 215F 216F to 250F 251F to 300F

(md) 38C to 52C 53C to 102C 103C to 121C 122C to 149C

< 10 F75N or F101 F101 F78 F78

10 to 100 F75N or F101 F101 F78 F78

101 to 200 F75N or F101 F101 F78 F78

Well Stimulation

> 200 F101 F101 F78 F78

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Benefits of Staged Foam Diversion

Effective zone coverage and damage removal

Design is based on specific reservoir
parameters
Customized treatment design is computer
generated and modified on the fly.
Non-damaging diverter system is used
Very cost effective
Easy to apply in the field using standard
Well Stimulation

products and conventional equipment

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Why Acidizing through Coiled Tubing

 Performing the treatment through CT avoids exposing the wellhead
or completion tubulars to direct contact with corrosive treatment
fluids.

 CT movement provides the ability to accurately place small volum es

of acid. Spotting the treatment fluid with CT will help to ensure
complete coverage of the interval.

 The CT pressure control equipment configuration allows the

treatment to be performed on a live well. The potential formatio n
damage associated with well killing operation and the corresponding
loss of production time are thereby avoided.

 Jetting effect is something that can be effective in smaller cas ings

and provided that a proper purpose built nozzle is used. This cannot
be achieved with conventional techniques.
 It is imperative, in many matrix treatments, to perform the well
Well Stimulation

flow back as soon as possible after the acid job.

 Spotting the treatment fluid also avoids the need to bullhead
wellbore fluids into the formation ahead of the treatment.
 Long intervals can be more effectively treated using techniques and
tools that have been developed for use with CT, This is particularly
important in horizontal wellbores.

©2005 Abalt Solutions Limited. All rights reserved

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Dual Inflatable Packer

Coiled Tubing

Connector and release

joint assembly
Deployment bar

Control section

Upper inflatable packer

Well Stimulation

Spacer section

Lower inflatable packer

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Downhole Sensor Package (DSP)

 Real-time downhole data acquisition system
– monitor temperature
– pressure
– casing collar
 Accurate BHP and BHT data for any well profile
 Evaluate - Treat - Evaluate
 Optimized diversion

Plasticcoated cable
inside CT string

M echanical
release sub
Well Stimulation

Cable clamp and assembly

check valve assembly

Pressur e and
temperature sensors
Treatment
ports/nozzle

©2005 Abalt Solutions Limited. All rights reserved

Abalt Solutions

Safety Considerations

 Flow back
 Unspent acid
 Masks
 Pin hole development
 Swivel leaks
 Communication devices
 Gas detectors - H2S
 Leather gloves/eye wash bottles/eye goggles
Well Stimulation

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Foam diversion CT Rig Up

Nitrogen /Foam
generation
package

BOP Kill Port

Pumping tee
below
pressure
control
equipment

Sample
Point

Production
Well Stimulation

Tubing

Choke
Manifold CT Nozzle/
Process and Recirculate
tools

Disposal

©2005 Abalt Solutions Limited. All rights reserved

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Pressure Control Equip. Configuration

BOP kill port - Acid corrosive fluids must

never be pumped through this port
Pump -in Tee - Avoid pumping
acid through the swab valve
Wing Valve - Preferred connection
for pumping and flowing
Casing Valve
Well Stimulation

Production Tubing

Coiled Tubing

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Introduction to Hydrocarbon Exploitation

Carbonate Acidizing

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Stimulation of Carbonates

 The injection of acids into carbonate reservoirs

leads to the formation of highly conductive flow
channels.
Matrix Acidizing Fracture Acidizing
Well Stimulation

Wormholes

Conductive
etch paths

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

HCl / Carbonate Rocks Rxns

 Limestone:
– CaCO3 + 2HCl ---> CaCl2 + CO2 + H20

 Dolomite:
– CaMg(CO3)2 + 4HCl ---> CaCl2 + MgCl2 +2H 2O
+ 2CO2
Well Stimulation

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Alternative Dissolution Patterns

Patterns change depending on:

– Temperature
– Injection velocity
– Surface reaction rate

Direction of
Well Stimulation

flow

Increasing Injection Rate

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Wormhole Pattern from Radial Flow

Acid

spent
acid
Well Stimulation

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Acid Systems

 HCl - Primary acid for

 Emulsified acids (SXE)
carbonates
– Retarded kinetics
 Organic acids -
 Non-acid solvents
Formic/Acetic
– Low corrosion
– Less dissolution – Retarded kinetics
capacity
– Higher temperatures
 Blended acids:
– HCl / organic blends
– Less expensive than
Well Stimulation

organic acids

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Introduction to Hydrocarbon Exploitation

Fracture Acidizing

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Fracture Acidizing
 The injected acid non uniformly etches the fracture
faces, resulting in the formation of highly conductive
etched channels that remain open after the fracture
closes.

 The success of the

treatment depends on
two characteristics of the
etched fracture:
– effective fracture length
– effective fracture conductivity Wormholes
Well Stimulation

Conductive
etched
channels

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Fracture Acidizing
Factors Influencing the Success of Fracture Acidizing
Treatments:
 Effective fracture length
– Rate of acid consumption
– Acid fluid loss (wormhole formation)
– Acid convection along the fracture

 Effective fracture conductivity

– Etched pattern
– Volume of rock dissolved
Well Stimulation

– Roughness of etched surface

– Rock strength
– Closure stress

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Fluid-Loss Problems

 Carbonates are usually Fissured

 Acid Destroys most Fluid Loss Additives
 Fracture Faces are Constantly Eroded
 Wormhole Formation
 Natural Fractures Enlarged
 Increased Leakoff Surface
 Fracture-Pressure Maintenance
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Introduction to Hydrocarbon Exploitation

Carbonate Acidizing

Chemistry and Physics

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Carbonate vs. Sandstone

CARBONATE SANDSTONE
– A large fraction of the – A small fraction of the
matrix is soluble matrix is soluble
(>50%)
– Dissolution of the
– Dissolution of rock damaging mineral
(wormholes)
damage bypassing – Precipitations

– Diversion
Well Stimulation

penetration + dissolution +
coverage precipitations

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Stoichiometry
2HCl + CaCO3 ---> CaCl2 + H2O + CO2

MgCa(CO3)2 + 4HCl ---> CaCl2 + MgCl 2 + 2H2O + 2CO2

 Stoichiometry refers to the proportions of the various

reactants participating in a chemical reaction. Knowing these
proportions allows one to calculate the amount of acid
required to dissolve a given quantity of carbonate rock.
 Allows determination of acid required

 Allows determination of increase

Well Stimulation

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Key Factors in Carbonate Acidizing

1. Penetration
2. Acid reactivity
3. Injection rates
4. Diversion
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Well Stimulation
Penetration

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Pore Level Model

One can explain the range of dissolution channels by studying the
competition between acid reaction and acid transport.

Mass Transfer
Acid Convection to Surface
Mass Transfer
to Bulk of acid
Well Stimulation

Acid Surface Reaction

Simple representation of a pore or wormhole.

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Damköhler Number, Da *

 The three parameters can be combined into

one dimensionless group:
Net Rate of Mineral Dissolution by Acid
Da =
Rate of Acid Convection

DL
Da =
Q
Well Stimulation

k is the overall dissolution rate constant

D is the wormhole diameter
L is the wormhole length
Q is the flow rate in the wormhole
*Fredd and Fogler, AIChE J., 1998.

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Wormhole Collision: pore-level stimulation

Acid invades porous matrix where it reacts with
the pore walls.

H+

H+
carbonate
Well Stimulation

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Wormhole Collision
Acid attack reduces pore wall thickness

H+

carbonate
Well Stimulation

Ever widening pore channels can

collide
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Effect of Da on Stimulation Efficiency*

1000
Pore Volumes
to Breakthrough
100
(Inverse of Acid
Efficiency)
10

1
0.1 1.0 10 100 1000
1 / Damköhler Number

The graph shown here depicts the relationship between the acid e fficiency (indicated by pore
Well Stimulation

volumes of acid required to breakthrough) and the Damköhler number. The x-axis is the
reciprocal of the Damkö hler number, which is proportional to the flow rate. In fact, all other
things being constant, 1/Da is Q. The y -axis shows pore volumes to breakthrough, I.e., volume
of acid required to propagate a wormhole that extends from the inlet to the exit of the core.
The shape of the curve is universal for all fluid/mineral system s. The implication is that one
wants to operate an acidizing treatment to the right of the mini mum (optimum).

©2005 Abalt Solutions Limited. All rights reserved

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Attack of Hydrochloric Acid on Iron

 Basic Reaction:
– Fe + 2HCl Fe++ + H2 + 2Cl-
 At Anode: Fe Fe++ + 2e-
Oxidation
 At Cathode: 2H+ + 2e - H2 Reduction
Well Stimulation

H + Cl - H+ - H
+ +
Cl - H Fe
++
Cl - H 2 H + Cl - Cl H + Cl -

e- e- e- e-
CATHODE ANODE

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Mechanisms of Inhibition

+ + ++
H H Fe
Fe ++
H+ H+

e- e- e-

Barrier at anodic surface (-) Barrier at cathodic surface (-).

At Anodic sites, electrons from
Well Stimulation

anionic inhibitor molecules

A corrosion inhibitor (Organic N2,Arsenic)
attach themselves and form a
film at the anodic sites. forms a barrier at a
cathodic surface or anodic surface which
At Cathodic sites, electrons from
cationic inhibitor molecules interferes with electrochemical reactions.
attach themselves and form a
film at the cathodic sites.
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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Inhibitor Effectiveness

 Concentration of Inhibitor
 Temperature
 Metal Type
 Concentration & Type of Acid
 Concentration & Type of Additives
 Pressure
 Flow Velocity
 Volume/Area Ratio
Well Stimulation

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Definition
 Surfactants, or surface active agents, are used in
acidizing to break undesirable emulsions, reduce surface
and /or interfacial tension, alter wettability, speed
cleanup, disperse additives, and prevent sludge
formation.
 Chemical containing both oil and water soluble groups

Hydrophilic Hydrophobic (Lipophillic)

M+ - Anionic
Well Stimulation

X- + Cationic

Non-Ionic

(pH) +
- Amphoteric

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Some Surfactants

 F100 Amphoteric
 F103 Non ionic
 F104 Anionic
 W060 Blend
 W62 Blend
Well Stimulation

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Reasons for Using Surfactants

 Control wettability
 Prevent/break water blocks
 Disperse/suspend fines
 Reduce capillary force
 Sludge prevention
 Asphaltene treatment
 Prevent/break emulsions
– Reduce surface or interfacial tension
 Enhance emulsions
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Water and Oil Wet Rock

 ionic for sandstone; cationic for carbonate

water wet oil wet
Well Stimulation

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Foaming Agents

 Diversion, cleanup
 Do not mix with hydrocarbons, mutual solvents,
alcohols

 F100
– Used with Nitrogen

 F52
– Used with Carbon Dioxide or Nitrogen
Well Stimulation

 Non-ionic not for T > 250 oF

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©abalt solutions limited - 2005 September – October 2005

INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sludge and Asphaltenes

Dispersed and stable Flocculated, precipitated

• pH

• Multivalent +Ca
+
cations
+
+
• Poor
solvents
Fe
+
+
+Fe

•Asphaltenes are the heaviest, most polar component of crude oil. They
are naturally dispersed by resins (maltenes).

•Poor solvents, Hydrogen ions, and multivalent metal ions (particularly

Well Stimulation

Fe[III]) will cause flocculation and precipitation. HCl with Ferric iron
(Fe[III]) will generally precipitate asphaltenes if present in the crude oil.

•The resulting asphaltene sludge is very difficult to remove even with

strong aromatic solvents.
•The asphaltene sludge contains many other materials (such as paraffin ,
or Iron Sulfide, fines, etc.)
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Factors Affecting Sludge

 Crude type
 Acid type
 Ferric iron
 BHST
 Antisludge agents:
– W60 (MISCA)
– W59
– B53
Well Stimulation

– B60

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Acid-Oil Mixing

Need for preflushes

Flow Back

Mixing of acid and the formation fluids will occur unless a large pad is injected
before the acid.
Well Stimulation

The mixing of live acid and oil during injection, and the mixing of spent acid
and oil during flow back (depicted above) can lead to the following problems:
1) Formation of stable emulsions
2) Change the formation wettability to oil wet (due to sludge precipitation)
3) Creation of Asphaltene sludge

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Anti-Sludge Strategy

 Minimize Fe concentration vendor’s quality

control
 Remove scales and rust
from equipment and tubing pickle
tubular surfaces lined equipment
 Reduce dissolution rate of
Fe ions from surfaces in corrosion inhibitor
contact with acid
 Reduce ferric ions to iron reducer
ferrous ions
 Enhance oil/acid break- oil sample
out
Well Stimulation

surfactant

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Surfactants to Control Acid Sludge

Dispersants to stabilize
B53, B60, W60, W58
Asphaltene fraction

Demulsifiers
B53, W53, W54, W59

Control iron L58, L63, A179, U42

Well Stimulation

 Use highly dispersible chemicals.

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Emulsions

 Treating fluid + crude oil + emulsifying agent

= emulsion

 Emulsion = reduced production

 Emulsion-stabilizer agents include:

– Asphaltenes
– Formation fines
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Types of Emulsion

 Inverse or oil-outside
emulsions
– oil is the continuous phase external phase
with the water droplets
dispersed

 Direct or water-outside
emulsions
-water-external emulsion internal phase
Well Stimulation

has an aqueous external

phase with oil droplets
distributed throughout

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Emulsion Blocking
 Crudes contain naturally occurring surfactants that
reduce the surface tension between oil and formation
water, and thus promote the development of emulsions
 A critical pressure drop must be imposed across pore
throats to mobilize interfacial films that stabilize foams
and emulsions.
Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Prevent/Break Emulsions

Water-outside Oil-outside Phase

Phase
U066 Clean Sweep I
U98
U100 Clean Sweep II
K46, F3
Clean Sweep III Paran Eco
Well Stimulation

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Mutual Solvent
– Mutual Solvents are multifunctional, non ionic
agents soluble in oil, water, acid and brines.

– They contain strong ether and alcohol groups,

which provide a wide range of solvent properties.
–
– The functions of Mutual Solvents are:
1. Wetting Agents
2. Non Emulsifiers
3. Surface/Interfacial Tension Reducer
Well Stimulation

Commonly used mutual solvents

 Ethylene glycol monobutyl ether (EGMBE)
 Ether/surfactant/alcohol blends

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Sour Wells-Fe Control

When appreciable quantities of iron in the form of Fe3+ (ferric ions), rather
than the usual Fe2+ (ferrous ions), are dissolved by the acid, iron
precipitation and permeability reductions can occur after acidizing

– Fe (OH)3 pH > 2 (pH > 6 in presence

of F - )
– Fe (OH)2 pH > 7

– Fe3+ + H2S Sulfur + Fe2+

– Fe2+ + H2S FeS pH > 2
Well Stimulation

Need to control Fe2+ too

The presence of H2S changes the iron precipitation problem. Sulf ur
precipitates in this reaction. At the same time, if the iron is reduced from +3
to +2, at a pH of about 2, Ferrous Sulfide, which is an insolubl e precipitate
will form
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Iron Control Practices

 Remove iron in tubing prior to stimulation

treatment (Pickle or use protected work-string)

 The acid must not contain high levels of Fe3+ -

Avoid contamination (Clean/lined equipment)

 Combinations of reducing agents and chelating

agents provide cost-effective solutions (L63,
U42)

 Utilize effective corrosion inhibitors (A260)

Well Stimulation

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Clay Control

 Clays: below 4m

– illite, smectite, chlorite, zeolite, kaolinite
 Silts: 4 – 64 m
– feldspar, mica, chert
fines
 Sands: over 64 m

 clays cause 2 major problems:

– 1. Swelling
– 2. Migration
Well Stimulation

KCl is temporary clay control agent

L55 is a permanent clay stabilizer that work by
adsorbing on the clay surface

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Friction Reducers
 Used during matrix acidizing through CT
 Suppress turbulence of the fluid
Action of friction reducers
(at a given flow rate)

•Natural polymers like guar gum, gum karaya and cellulose derivat ives, as
Well Stimulation

well as synthetic polyacrylamides, have long been used as friction reducers.

•Each of these polymers can have different properties, depending on
molecular weight, chemical composition, cross linking, branching, etc.
•Some polyacrylamides (i.e., Friction-Reducing Agent J120) are excellent
friction reducers for acid and can greatly reduce the friction pressure drop in
tubulars

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INTRODUCTION TO HYDROCARBON EXPLOITATION
Development Phase

Thank You
Well Stimulation

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©abalt solutions limited - 2005 September – October 2005