pab 4323 l3
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PAB 4323 – WELL STIMULATION
TECHNIQUES
SEMESTER 7
By
Dr. Aliyu Adebayo Sulaimon([email protected])
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Course Major Contents
Well stimulation techniques
Reasons for stimulating
Primary forms of well stimulation• Wellbore clean-up
• Matrix treatment
• Fracturing
Candidate selection
Selecting a technique
Assignment and Review
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Learning Outcomes
At the end of this lecture, students should be able to: Describe how flow capacity reduction can occur
Describe what is a good stimulation candidate
Name the three primary stimulation methods
Describe the difference between matrix and fracture
stimulation
Know the two types of fracture stimulation
Describe the two types of fracturing technique for low and
higher permeability formations
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Figure 1: Components of sedimentary rocks
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Purpose of Stimulation
To enhance the property value by the faster delivery of the petroleum fluid
To increase ultimate economic recovery
Flow Near Wellbore
Skin effect „S‟ is used to describe alterations in the near-wellbore zone.
Recall, permeability damage is a common problem caused by practically any
well operation e.g. drilling, completion, perforation or stimulation itself
If „k‟ is significantly reduced, then the largest portion of the total pressure
gradient may be consumed within the very near wellbore zone
=
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Increase production efficiency or flow capacity• Overcome formation damage
• Enhance production from low permeability wells
Connect with natural fracture system
Increase effective drainage area
Produce complex reservoirs (e.g. discontinuous sand bars)
Increase wellbore stability (minimize drawdown)
Reasons for Stimulation
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Stimulation Techniques
Basically, there are three ways of well stimulation: Wellbore Clean-up (Fluids not injected into formation)
Chemical Treatment
Perf Wash
Matrix Treatment (Injection below fracture pressure)
Chemical Treatment
Matrix Acidizing
Fracturing (Injection above fracture pressure)
Acid Frac
Propped Frac
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Candidate Selection
Requirements:
Selection of candidate wells
Selection of the specific treatment
Design
Economic Justification (Do or not)
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Selection of candidate wells
Good candidates
Damaged wells
Tight reservoirs (refer to the journal articles provided)
Medium candidates
Naturally fractured reservoirs
Unconsolidated, high permeability reservoirs
Bad candidates
Limited reserves
Low pressure reservoirs where fracture fluid flow back forcleanup is difficult (in case of hydraulic fracturing)
Stimulation and reservoir fluids not compatible
If stimulation can penetrate water zones (water production)
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Selection of Treatment Technique
Productivity target, drawdown limit and zonal isolation determine
the stimulation technique
Productivity
Sandstone reservoirs• Matrix stimulation if 10% reduction in skin would achieve
productivity target
• Hydraulic fracturing is the best alternative
Carbonate reservoirs
• Matrix stimulation if -2 to -3 skin would achieve productivity
target
• Acid fracturing can be cost-effective
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Selection of Technique (Cont‟d)
Drawdown Limit
In unconsolidated or friable sands, the max. allowable
pressure drop should not be exceeded in order to prevent
sand production
Limitation favours fracture stimulation to achieve target
rate at lower drawdown
Zonal Isolation
If vertical fracture growth into an aquifer or gas cap
cannot be controlled, matrix stimulation is a better choice
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Stimulation Techniques
Wellbore Cleanout
Perforations and tubular goods may become clogged with
deposits over a period of time
Deposits (products of corrosion, bacteria & scales, paraffin and asphaltene
buildup will restrict the well‟s flow capacity
Main purpose of technique is to restore flow capacity by
removing the wellbore damage
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Wellbore Cleanout (Cont‟d)
Methods
Mechanical
• Require a metal scraper and a coiled tubing unit (Figure 2)
• The coiled tubing could be used to circulate sand fill out of the
hole, as well as perforation wash „rotating jet tool‟ Chemical Treatment
• Consists of one or a combination of surfactants, organic
solvents, bactericides, scale removers/inhibitors, mutual
solvents and clay dispersant/stabilizers
Acid Treatment
• Involves pumping an acid and placing it at the restriction depth to
dissolve the restriction or weaken it for easy removal (Figure 3)
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Figure 2: Coiled Tubing Unit
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Figure 3: Acid Pumper
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Stimulation Techniques
Matrix Stimulation/Acidizing
Accomplished by injecting a fluid (e.g. acid or solvent) below
the fracturing pressure of the formation
Acid treatment process under wellbore cleanout is similar to
matrix stimulation process in sandstone formation; the acid
dissolves and/or disperse materials that impair well
production.
In carbonate formation, the acid dissolves the rock to createnew unimpaired (high conductivity) flow channels (i.e.
wormholes) between the wellbore and the formation (Figure 4) (Further reading: Refer to the provided article - „Stimulate the Flow‟)
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Figure 4: Neutron radiographs of wormholes formed during the dissolution of limestone by 0.25-MEDTA injected at pH 4.
Q = 0.01 cm-’/min Q = 0.025 cm3/min Q = 0.06 cmi/min Q = 0.15 cm’/min Q = 1.0 cni3/min Q = 3.0 crn3/min
Damt = 8.7 Damt = 3.5 . Damt= 1.5 Damt = 0.6 Damt = 0.09 Damt = 0.03
PVinj= 20.0 PVBT = 3.7 PVBT = 2.6 PVBT = 3.6 PVBT = 10.6 PVBT = 16.2
Source: Fredd, C.N. and Fogler, H.S. (1998): „Influence of Transport and Reaction on Wormhole Formation
in Porous Media‟, AIChE J., 44, 9, (Sept.), 1933-1949
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Fig 5a: Top view of wormhole structure, Test 1. Fig 5b: Side view of wormhole structure, Test 2.
Source: McDuff, D.; Jackson, S.; Shuchart, C.; and Postl, D.(2010):‟Understanding Wormholes in
Carbonates: Unprecedented Experimental Scale and 3D Visualization‟, (SPE 129329), JPT ,
Oct, 78-81.
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Treating Chemicals
Multiple fluids composed of base fluids and additives are selected based on
lithology, damage mechanism and well condition. The main treating fluid isselected to bypass the damage with acid or dissolve with solvents (in carbonate);
while its chosen to dissolve or disperse the principal damage (in sandstone)
Chemical Categories Solvents:
• Remove organic deposits (e.g. Paraffin)
Oxidizers:• Remove damage from polymers
Scale removers:
• Remove sulfate or oxide scales
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Chemical Categories
Acids:
• Remove carbonate and oxide scales
• Break polymer residues
• Stimulate carbonate formations
•
HF removes alumino-silicate (primarily clays) damage from sandstoneformations
• In carbonates, HCl or organic acids (formic or acetic) are used to etch
conductive paths between the wellbore and the formation
•In sandstones, mixtures of HCl and HF are used to remove drilling mud, fines(in-situ/generated), and perforation residue.
Acids are widely used for matrix stimulation because they are effective
against several types of damage and are relatively inexpensive.
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Application and Comparison of Acids
ACID STRENGTH FORMATION REMARKS
HCl15-28% by
weightCarbonate Highly corrosive (above )
Mud Acid 9% HCl+1% HFSilica
sandstone
HCl used prior to treatment to
remove + Highly corrosive
Acetic 10% by weight Carbonate Less corrosive than HCl but moreexpensive
Formic 9% by weight Carbonate
Less corrosive than HCl.
More corrosive and less
expensive than acetic acid
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Stimulation Techniques
Hydraulic Fracturing
What happens if fluid is pumped into a well faster than the the
fluid can escape into the formation?
Pressure rises and at some point something breaks.
The formation breaks, resulting in the wellbore splitting along
its axis as a result of tensile hoop stresses generated by the
internal pressure
“Hydraulic” fracture is created when the wellbore breaks or
the rock fractures due to the action of the hydraulic fluid
pressure
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Fracture direction and geometry
Fractures are always perpendicular to the minimum stress,except in formation with very complex geology
Since most wells are vertical and the smallest stress is the
minimum horizontal stress, the initial splitting results in avertical, planar parting in the earth
For relaxed geological environments, the minimum in-situ
stress is usually horizontal
In areas of acting tectonic compression (faulting), the min.
stress is vertical
Vertical Fracture
Horizontal Fracture
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Figure 6: Stress element and
preferred plane of
fracture
What if the least
principal stressbecomes the
highest?
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Types of Hydraulic Fracturing
Basically there are two types:
Propped Fractures
Acid Fracture
Propped Fracture• If the pumping rate is maintained at a rate higher than the fluid-loss
rate, the newly created fracture will continue to propagate and
grow (i.e. open more formation area)
• When pumping stops and the injected fluids leak off, the fracturewill close.
• To prevent this, measures must be taken to maintain the
conductive channel.
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Propped Fracture (Cont‟d)
• A propping agent is added to the hydraulic fluid to be transported
into the fracture• When pumping stops and fluid flows back from the well, the
propping agent remains in place to keep the fracture open
• Propping agent is generally sand or a high strength, granular
substitute for sand. [Figure 7(a)-(c)] • Expectedly after breakdown, fracture propagation rate and fluid
flow rate inside the fracture are dominated by fluid-loss behaviour
• Risk of a screen-out and subsequent problems of proppant
flowback and cleanout from the wellbore
• Not all of the fracture is usable (Figure 7)
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Figure 7(a): 20/40 Northern White fracturing sand.
Photo courtesy: Santrol Proppants.
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Figure 7(b): 20/40 SLC resin-coated sand.
Photo courtesy: Santrol Proppants
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Figure 7(c): CARBOEconoprop 20/40, a high-conductivity,
lightweight ceramic proppant from CARBO
Ceramics
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Figure 8
P S l
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3. Review Proppant Database finding proppants matching required mesh sizes,
formation closure stress and temperature
1. Calculate optimal fracture half-length
and conductivity
4. Select proppants with required conductivity
5. Sort selected proppants by price;
Select proppant flowback control additives
2. Determine applicable proppant mesh sizes
Proppant Selection
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Acid Fracture
• First attempt of HCl to prevent corrosion of w/b tubulars
in a limestone formation (observed “lifting pressure”enhanced)
• Any difference between acid and propped fracturing?
Means of achieving fracture conductivity after the
fracture closes; an etched pattern of voids on the
fracture faces and propping the faces apart,
respectively
• Operationally, acid fracturing is less complicated becauseno propping agents are used
• Risks of screen-out, flowback and cleanout associated
with propped fracture are eliminated
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Acid Fracture
• Barriers to effective acid penetration are:
•
The distance the acid travels along the fracture beforespending limits the effective length of an acidized fracture,
especially at high temperatures.
• Excessive fluid loss
Continuous acid corrosion and erosion of the fracture faces duringtreatment retard the deposition of an effective filter cake barrier
Acid leak-off is highly non-uniform and typically results in wormholes
and the enlargement of natural fractures and matrix permeability
Acid fractures are used in carbonates
Propped fractures are more appropriate for sandstones
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Length, Width and Conductivity
Fracture‟s length and width are function of formation
permeability For a low-k sandstone, what matters is the length of the
fracture. Fluid flows easily into the fracture from several
sections of the reservoir. For a high-k sandstone, the relevant factor is the width. The
aim is to reduce the pressure drop near the wellbore; this is
achieved with a “fat” fracture
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Proppant
Low permeability zone
Damaged zone
High permeability zone
Damaged zone
Figure 9: Length and width in high and low permeability sandstones
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Length, Width and Conductivity
In terms of flow rate:
• Fracturing a low permeable zone can lead to increase inproduction
• Fracturing a high permeable zone may accelerate
production
With regard to cumulative production:
•
Fracturing a low permeable zone can ensure a significantincrease in the ultimate recovery
• For a high-k zone, fracturing can facilitate achieving faster
ultimate recovery
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F l o
w
r a t e
Time
Low permeability
With stimulation
Without stimulation F l o w
r a t e
Time
High permeability
With stimulation
Without stimulation
Economic limit
Economic limit
Figure 10: Effect of fracturing on flow rates of low and permeable zones
F l o
w
r a t e
Time
Low permeability
With stimulation
Without stimulation
C u m
. P r o d .
Time
High permeability
Ultimate recovery
Figure 11: Effect of fracturing on total production of low and permeable zones
With stimulation
Without stimulation
Ultimate recovery
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Questions?
Thank you