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Copyright 2006 by Faruk Civan -All rights reserved
1
Formation Damage Mechanisms
FARUK CIVAN, Ph.D.Alumni Chair ProfessorMewbourne School of Petroleum and Geological EngineeringThe University of Oklahoma
Copyright 2006 by Faruk Civan -All rights reserved
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Presentation OutlineHow is formation damage defined?What does formation damage do?How does formation damage occur?What are the common formation damage mechanisms?How can we control formation damage?
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Formation DamageAn expensive headache (Amaefule et al. 1988)
Requires interdisciplinary knowledge and expertise
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Damage Mechanisms(Butler et al., 2000)
Formation damage:Impairment of reservoir permeability by adverse processes
Completion damage:Hinderence of well productivity by deposition and flow modification at and around well bore
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Mechanical Skin (Formation Damage (Yildiz, 2003)
Porosity and permeability variation byFines migration and depositionMud filtrate and fines invasionRock compressionScalesAcidizing
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Near Wellbore Damage
Damaged Region Non-damaged Region
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Effect of Anisotropy and Stress on Damage Zone
KH > KVKH < KV
Invasion Zone
Well
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Formation DamageIndicators
Permeability impairmentSkin damageDecrease of well performance.
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Pressure Profile and Skin
Pw
rorw
t > 0 , s > 0
Pwo
t = 0, s = 0P
r
t > 0 , s < 0
Pw
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Formation Damage Measure- Skin Factor
actualws
apparentw rer )()( −=re
rdrw
Damaged Region
Non-Damaged
Region
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Consequence of Formation Damage
Reduction of reservoir productivityNon-economic operations
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Formation Damage“Not necessarily reversible”(Porter, 1989)What gets into porous media does not necessarily come out” (Porter, 1989)Avoid formation damage than to restore it
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Potential Sources of Formation Damage During History of Well
1. Drilling (emulsion block, wettability change, mud damage, mechanical damage)
2. Cementing (pH change, scale formation)
3. Perforating 4. Completion
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Potential Sources of Formation Damage During the History of the Well…
5. Workover6. Gravel packing7. Production8. Stimulation9. Fluid injection
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Common Formation Damage Mechanisms(Bennion, 1999, Bennion and Thomas, 1991, Bishop, 1997)
1. Fluid-fluid incompatibility (emulsion generation, etc.)
2. Rock-fluid incompatibility (clay swelling, etc.)
3. Fines invasion and migration (particles, etc.)
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Common Formation Damage Mechanisms(Bennion, 1999, Bennion and Thomas, 1991, Bishop, 1997)
4. Phase trapping and blocking (water entrapment in gas reservoirs)
5. Adsorption and wettability alteration6. Biological activity (bacteria, slime
production).
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What do Rocks contain?(Bucke & Markin,1971, Ezzat,1990, Mancini,1991)
1. Mineral oxides (SiO2, Al2O3, etc.)2. Swelling and non-swelling clays
(detrital and authigenic)3. Other substances (mud, cement,
and debris)
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Clay MineralsCrystalline minerals described as hydrous aluminum silicates1. Kaolinite group (breaks apart
into fine particles)2. Smectite or montmorillonite
group (water sensitive and expandable)
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Clay Minerals…
3.Illite group (plugs pore throats)4.Mixed-layer clay minerals
(breaks apart in clumps and form bridges across pores)
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Extraneous MaterialsForeign materials introduced during:
Drilling and completion of wellsWorkover operationsEnhanced recovery processes
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Externally Introduced Particles
Fluid loss control materialsBentoniteClays
Mud weighting materialsCalcium carbonateBariteHematite
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Externally Introduced Particles
Pore bridging materialsFibersResinsSilicaCalcium carbonate
Injection water materialsBacteriaSand, clay, silt, asphaltene, wax, polymersMaterials produced by corrosion of tubing
Particulate matter produced by drilling
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Porous Media RealizationLeaky-tube Model
(Civan, 2003)Network Model
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Bundle-of-Leaky-Capillary-Tubes Model of Porous Media
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Porosity-Permeability Alteration
1.0E-18
1.0E-17
1.0E-16
1.0E-15
1.0E-14
1.0E-13
1.0E-12
1.0E-11
0.00 0.05 0.10 0.15 0.20Porosity, φ, fraction
Perm
eabi
lity,
K, m
D
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Formation Damage Causing Rock-Fluid Interactions(Bennion and Thomas, 1994)
1. Mobilization, migration, and deposition of fine particles (internal or external)
2. Alteration of porous media and particle surface (absorption, adsorption, wettability change, and swelling)
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Formation Damage Causing Rock-Fluid Interactions…(Bennion and Thomas, 1994)
3. Other processes (mud fluid imbibition, grinding and mashing of solids, surface glazing)
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Deposition Within Porous Formation
DEPOSITIONENTRAINMENT
FLOW
TYPICAL HYDRAULIC TUBE
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Shock Phenomena Causing Particle Detachment and Mobilization
Three Important Criteria:
Critical salt concentrationCritical interstitial fluid velocityCritical temperature
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Salinity ShockSalinity Shock
Civan (2000, 2001)Civan (2000, 2001)
CSC : Critical salt concentration (CSC : Critical salt concentration (KhilarKhilar and and FoglerFogler, 1983), 1983)
Bas
al S
paci
ngSalt Concentration
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Particle swelling Particle swelling
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Critical Mobilization VelocityCritical Mobilization Velocity
GruesbeckGruesbeck and Collins (1982)and Collins (1982)
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Particles experience more fluid shear in tortuous paths (Civan, 2006)
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Temperature ShockTemperature Shock
Gupta and Civan (1994)Gupta and Civan (1994)
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Small Particles Deep-bed Filtration
Suspended particles
Immobile particles
Fluid velocity decreases with radial distance
Tortuous flow path
Well
Reservoir region of well influence
Hydraulic fracture
Critical velocity
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Particle Deposition Mechanisms
Surface deposition
Pore throatplugging
Pore fillingand internal
cake formation
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Valve effect of pore throats Valve effect of pore throats
Chang and Civan (1997) and Ochi and Vernoux (1998)
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Pore Throat Plugging Deposition
Dp Dt
0
p
t
DD
=β
( )µφpp
p
uDc=Re
Non-bridging
Bridging
( )Re1 pBcr A e Cβ −= − +
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Dislodgement/deposition at Pore Throats
Flow Reversal
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Particle aggregation kinetics Particle aggregation kinetics
Diffusion-limitedReaction-limited
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Medium to Large ParticlesExternal Cake Formation
Large particles
(Screening)
Medium particles
(Bridging)
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Filter Cake Distribution
Vertical Well•Radial filter cake•Homogeneous thick
r, radial direction
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Filter Cake Distribution…
Horizontal Well•Rotation effect•Gravity effect•Non-uniform thick
Gravity direction
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Perforated Wells
x
y
Perforation
Invaded Zone
Uninvaded Zone
Filter Cake
Wellbore
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Hydraulically-Fractured Wells
x
y
Perforation
Invaded Zone
Uninvaded Zone
Wellbore
Filter cake
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Conditions Favorable for Sand Production(Hayatdavoudi, 1999)
1. Lack of cementation and loss of mechanical integrity
2. Small grain size3. Weak consolidation and
compaction
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Conditions Favorable for Sand Production(Hayatdavoudi, 1999)
4. Rising water tableHigher water cut Petrophysical alteration
5. Grain buoyancy effect6. High flow rate and low
pore fluid pressure
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Sand Liquefaction Criterion (Hayatdavoudi, 1999)
Friction shear-stress > Critical-shear-stress
θτ
x
y
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Massive Sand Production…(Geilikman and Dusseault, 1994, 1997)
rw reR(t)
Yielded Zone
IntactZone
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Practical Results
00
qs
t
Sand Production
Rate
00 t
Fluid Production
Improvement
o
f
qo = flow rate withoutsand production
qf = flow rate withsand production
1.0
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Sand Control Methods(JPT, 1995)
1. Sand control is necessary for weak formations and high water influx.
2. Hydraulic fracturing reduces the flow rate and pressure gradient to prevent sanding.
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Sand Control Methods(JPT, 1995)
3. Zone perforation and frac-packing (gel or water packing)
4. Resin injection for chemical consolidation
5. Gravel packs, screens, and slotted liners to filter sand.
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Sand Control Methods(JPT, 1995)
6. Dropping the water level by special completion techniques (Hayatdavoudi, 1999):a) Horizontal wellsb) Water production from below
the oil/water contactc) Reducing water-coning.
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WettabilityDefinition:1. Preferential affinity of solid to
fluid phases2. Tendency of fluids to spread
over solid surface
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Contact Angle
θ < 90o, strong wettabilityθ > 90o, weak wettabilityθ 90o, intermediate wettability≈
θ
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Wettability Effect(Durand and Rosenberg, 1988)
Water-wet (Clay/Oil)
Oil-wet (Clay/Oil)
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Wettability Alteration
Oil-wetSite
Water-wetSite
Pore SpaceOil
adsorbed
Water adsorbed WI
Oil Adsorption(mg/g)
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Wettability…Wettability alteration can be detected by capillary pressure measurement
Pc 0
250oF
100oF
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Particle Migration in MultiParticle Migration in Multi--phase Flowphase Flow
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Formation Damage Causing Fluid-Fluid Interactions(Amaefule, 1988, and Masikewich and Bennion, 1999)
Emulsion blockingInorganic depositionOrganic deposition
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Liquid Phase Entrapment
FiltratesWater basedOil based
CondensatesWaterHydrocarbon
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Phase Entrapment(Bennion, 2003)
Wetting phase Wetting
phase
Wetting phase
Non-wetting phase
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Relative Permeability Alteration and Liquid Block(Keelan and Koepf, 1977)
Before damage After damage
Kr vs. Sw Kr vs. Sw
Shrinking of mobile fluid saturation range
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Natural and Induced Scale Damage(Shaughnessy and Kline, 1983)
0Dissolved Ca2+
Dissolved HCO-
3mol/lt Na
tura
l
Induced
Add incompatible fluid
)(2)(2)(332 02 lgs HCOCaCOHCOCa ++↔+ −+
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Calcite solubility in water(Segnit et al., 1962)
)(22)(332 2 gs COOHCaCOHCOCa ++⇔+ −+
Calcite Solubility
g/kg solutionpCO2
150 oC200 oC
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Saturation Index (Schneider, 1997)
=
sp
ap
KK
SI 10log
Supersaturated
Saturated
Undersaturated
C, Concentration of aqueous solution, mol/L
SI > 0
SI = 0SI < 0
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Organic Deposition
1. Paraffins (dissolved in oil)2. Asphaltenes (undissolved, but
suspended as a colloid in oil) 3. Resins (peptizing agent,
dissolved in oil, help suspend asphaltene in oil)
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4. Wax: A combined deposit of paraffins, asphaltenes, resins, mixed with clays, sand, and debris (dissolved in oil)
Organic Deposition…
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Asphaltene and Wax Phase Behavior (Leontaritis, 1996)
Temperature
Pres
sure
Liquid + Vapor
Liquid
Saturation
Bubble-Point Line
Lower depositionboundary
Upper depositionboundary
Liquid+Solid+VaporRegion (Pressure and
Composition dependant)
Liquid+Solid Region (Mostly pressure
dependant)
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Electrokinetic Effect(Mansoori, 1997)
Pipe or Capillary Tube
Streaming PotentialDifference
NegativeCharge
PositiveCharge
Asphaltene deposits
•Asphaltene is positively charged•Oil phase is negatively charged
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Evaluation of Common Formation Damage Problems(Keelan and Koepf, 1977)
Pore blocking by drilling, completion, workover, and injection fluidsClay hydration, swelling, dispersion, and pore blocking resulting from clay-water reactions
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Evaluation of Common Formation Damage Problems…(Keelan and Koepf, 1977)
Liquid block resulting from extraneous water introduction during drilling, completion, and workoverCaving and sand production
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Analysis of Core Damage Data
L
Permeability
PLuK
∆=
µ
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Constant-Pressure Difference Test
Permeabilityratio,K/Ko
PV-injected
∆P-small
∆P-large
00
1.0
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Core Plugs Wafers (Acid soak Experiments)
1-inch diameter
0.25-inch thick
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A Simple Linear Core Flow Testing Set-up (Doane et al., 1999)
CoreFluid
Reservoir
DisplacementPump
AnnulusPump
PressureTransducer
Effluent
Fluid collector
Core Holder
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Annular Flow Tester (Saleh et al., 1997)
Pump
Fluid Reservoir Radial Outward
Flow
Effluent
Fluid collector
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Drilling of Wells(Yao and Holditch, 1993)
UninvadedZone
MudInvasion
Mud In Mud Out
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Depth of Filtrate Invasion
Time
Depth ofInvasion
Water mud
Low-colloidoil mud
Oil mud
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Saturation Profiles for Mud Filtrate Invasion(Yao and Holditch, 1993)
WellboreSw = Swc
Mud Cake
Radial Distancerw re
Sw = 1- Sor
t1t2 t3Filtrate
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Dynamic Mud Tester
Pump MudReservoir
Core
Mud
Filtrate
LinearFlow
Effluent
Fluid collector
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Hydraulic Fracturing Fluids(Keelan and Koepf, 1977)
Water-blockSolids invasionLeak-off and spurt lossClay hydration
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Fracture Flow Tester(Doane et al., 1999)
Fracture
Flow
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Mitigation Methods(Masikewich and Bennion, 1999)
Emulsion blocking: Apply demulsifierPrecipitates: Apply wax, scale, and alkaline controlMigrating clays: Apply cationSwelling clays: Apply cation or polymer
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Mitigation Methods(Masikewich and Bennion, 1999)
Phase trapping and blocking: Apply alcohol, oil, and interfacial surface tension (IFT) reducerWettability alteration: Apply surfactantSolid invasion: Apply cake inducing agent
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Treatment Fluids(Thomas et al., 1998)
Proper AdditivesMajorTreatment
= Treating + to controlFluid
Chemical further damage
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Treatment Fluids(Thomas et al., 1998)
Additives can control:CorrosionSludge formationEmulsion formationOrganic and inorganic precipitation
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Treatment Fluids(Thomas et al., 1998)
Additives can control…Homogeneity
Clay stabilization
Interfacial tension
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Fracture Stimulation(Keelan and Koepf, 1977)
Hydraulic fracturingBypass damaged region
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Bypassing Damage by Hydraulic Fracturing
x
yz
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Completion Techniques
Open-hole completionsCavity completionsHydraulic fracturingFrac-and-packsHorizontal wells
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Reservoir Fluid Pattern- Open Hole vs. Perforated Cased Hole
Invasion Zone
Well
Perforation
Fluid goes through damaged zone
Fluid bypasses damaged zone
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Perforated Well Flow Efficiency(Chen and Atkinson, 2001, Yildiz, 2002)
Wellbore radiusShut densityShut anglePerforation depthPerforation diameterCrushed zone thicknessDamaged zone thicknessReservoir anisotropy
Crushed
zone
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Partial Completion and Deviation(Al Qahtani and Al Shehri, 2003)
hc
Perforated Zone
H
zc
L
Elevation to mid point
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Horizontally Fractured Well
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Vertically Fractured Well
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Frac-and-Pack Completion
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Multi-lateral Wells Completion
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Damage Tolerance of Completion Techniques from Most to Least(Jahediesfanjani and Civan, 2005)
Long horizontal wellsShort horizontal wellsHorizontally fractured wellsCavity completionsVertical wellsFrac-and-Pack completionsFractured wellsVertical wells
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Final Remarks
Formation damage mechanisms vary depending on the well operation types and reservoir and fluid conditions.Oil and gas recovery can be enhanced by minimizing and controlling of formation damage.
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Thank you for your attention
Questions?Discussions?Comments?