06 formation damage
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06 Formation DamageTRANSCRIPT
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Formation Damage
Types of Damages and Origins, Skin Factor and Productivity Index, Flow Efficiency
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Origin of Formation Damage
Formation damage – Types– Origin– Location
Diagnosis Removal and Prevention
– Methods– Chemistry
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Formation Damage Characterization
Fines Migration Swelling Clays Scale Deposits Organic Deposits
– Paraffins– Asphaltenes
Mixed Deposits Bacteria
Induced Particles– Solids– LCM/Kill Fluids– Precipitates
Oil Based Mud Emulsion Block Wettability Changes Water Block
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Swelling Clays: Smectite
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Migrating Clays: Kaolinite
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FINES MIGRATION MECHANISMFINES MIGRATION MECHANISM
fineswetting phase
non wetting phase
non wetting phase
non wetting phase
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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/near wellbore formation.
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Drilling Fluid Damage
Mud filtrateinvasion
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RDF (STARDRILL) Filter Cake
Filter cake Formation
Drilling Damage
Filter cake should prevent extensive damage to formation during drilling
Low permeability (~ 0.001md) 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 to bypass any damage
Filter cake removal maybe a necessity!
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Drilling Damage
Drilling Mud Solids– Particle Size vs. Pore
Size/Fissures– Filtration - 3 inches– Poor Mud Cake– Overbalance
Drilling Mud Filtrate– Formation Sensitivity (pH,
salinity, scale)– High Penetration Capillarity– Fines Dispersion– Additive Residues– Cooling
Oil Based Muds– High Solids Oil – Invasion/Relative Permeability– Cationic Emulsifiers
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Perforations
Debris Compacted Zone
Rad
ial
Dis
tan
ce (
mm
)
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Completion Fluids Damage
Suspended Solids– Polymer Residue
Fluid Loss Control– Formation Sensitivity– Clays– Wettability– Scales
A (2.5 ppm)
C (94 ppm)
D (436 ppm)
Per
mea
bili
ty (
md)
Volume Injected (gal/perf)
500
100
50
100 0.02 0.04 0.06 0.08 0.10
(A) Bay Water FilteredThrough 2um Cotton Filer
(B) Bay Water Through 5um Cotton Filter
(C) Produced Water Untreated
(D) Bay Water Untreated
B (26 ppm)
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Water Block Damage
A reduction in effective or relative permeability to oil due to increased water saturation in the near wellbore region.
Favored by pore-lining clay minerals (Illite)
Treatment Þ Reduction of interfacial tension using surfactants/alcohol's in acid carrier
1 1
Kro Krw
0
0 1Swc 1-SorSw
Water Wet
Oil Wet
Kro
Krw
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Damage due to Production
In an oil reservoir, pressure near well may be below bubblepoint, allowing free gas which reduces effective permeability to oil near wellbore.
In a retrograde gas condensate reservoir, pressure near well may be below dewpoint, allowing an immobile condensate ring to build up, which reduces effective permeability to gas near wellbore.
p < pbp > pb
The main Production damage is due to Fines Migration
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Damage Quantification
The Damage is quantified by the Skin Factor and the Productivity Index
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Reservoir Model of Skin Effect
Bulkformation
h
rw
ka
ra
Alteredzone
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Reservoir Pressure Profile
Distance from center of wellbore, ft
500
1000
1500
2000
1 10 100 1000 10000
Pre
ssu
re, p
si
ps
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Skin and Pressure Drawdown
k = Permeability, mdh = Height, ftq = Production, STB/DB = Oil Volume Factor, bbl/STBps = Pressure drawdown, psi = Oil Viscosity, cp
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Radial Production and Skin
q = Production, STB/Dk = Permeability, darcyh = Height, ftPr = Reservoir Pressure, psiPwf = Bottomhole Flowing
Pressure, psi = Oil Viscosity, cpBO = Oil Volume Factor, bbl/STBln = natural logaritmre = drainage radius, ftrw = wellbore radius, fts = skin factor
(Darcy’s Law)
srr
lnB141.2
PPhkq
w
eO
wfr
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Skin Factor and 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.
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Effective Wellbore Radius
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Geometric Skin – Converging Flow to Perforations
When a cased wellbore is perforated, the fluid must converge to the perforations to enter the wellbore. If the shot spacing is too large, this converging flow results in a positive apparent skin factor. This effect increases as the vertical permeability decreases, and decreases as the shot density increases.
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Geometric Skin - Partial Penetration
When a well is completed through only a portion of the net pay interval, the fluid must converge to flow through a smaller completed interval. This converging flow also results in a positive apparent skin factor. This effect increases as the vertical permeability decreases and decreases as the perforated interval as a fraction of the total interval increases.
h
hp
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Partial Penetration
hp
ht
h1
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Geometric Skin - Deviated Wellbore
sechh
S
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Geometric Skin - Well With Hydraulic Fracture
rw
r’w
sww err '
For example,
rw = 0.4 fts = -3
rw’ = 8 ft
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Completion Skin
rdp
Lp
kR
kdp
kd
rp
rd
rw
After McLeod, JPT (Jan. 1983) p. 32.
sp- geometric skin due to converging flow to perforations
sd - skin due to formation damage sdp - perforation damage skinkd - permeability of damaged zone around wellbore,
mdkdp - permeability of damaged zone around
perforation tunnels, mdkR - reservoir permeability, mdLp - length of perforation tunnel, ftn - number of perforationsh - formation thickness, ftrd - radius of damaged zone around wellbore, ftrdp - radius of damaged zone around perforation
tunnel, ftrp - radius of perforation tunnel, ftrw - wellbore radius, ft
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Gravel Pack Skin
Lg
Cement
Gravel
sgp - skin factor due to Darcy flow through gravel packh - net pay thicknesskgp - permeability of gravel pack gravel, mdkR - reservoir permeability, mdLg - length of flow path through gravel pack, ftn - number of perforations openrp - radius of perforation tunnel, ft
Does not include effects of non-Darcy flow (high-rate gas wells)
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Productivity Index
The productivity index is often used to predict how changes in average pressure or flowing bottomhole pressure pwf will affect the flow rate q.
The productivity index is affected by– Reservoir quality (permeability)– Skin factor
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Flow Efficiency
We can express the degree of damage on stimulation with the flow efficiency.For a well with neither damage nor stimulation, Eff = 1.
For a damaged well, Eff < 1
For a stimulated well, Eff > 1
wf
swf
ideal
actualff pp
Δppp
J
JE