16.00 CIVAN

Copyright 2006 by Faruk Civan -All rights reserved

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Formation Damage Mechanisms

FARUK CIVAN, Ph.D.Alumni Chair ProfessorMewbourne School of Petroleum and Geological EngineeringThe University of Oklahoma


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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

qq

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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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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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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Additives can control:CorrosionSludge formationEmulsion formationOrganic and inorganic precipitation


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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?

16.00 CIVAN

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