2.

1 Formation Damage

4.1 Formation damage

 Objectives

Skin Factor and Productivity Index, Flow Efficiency, Types of

Damages and Origins

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 Damage Quantification

The Damage is quantified by the Skin Factor and the

Productivity Index

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 Skin Factor
The skin factor is a measurement of the difference between the ideal and the real inflow
performance of a well.

A numerical value used to analytically model the difference from the pressure drop
predicted by Darcy's law and the actual pressure drop, due to skin.
Typical values for the skin factor range from -6 for an infinite-conductivity massive
hydraulic fracture (stimulated well) to more than 100 for a poorly executed gravel pack
(damaged well). This value is highly dependent on the value of kh.

0.00708 k h Ps  s 0= Damage

s s =0= Not damaged
q BO s 0= Stimulated

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 Skin Effect
The well Skin Effect is a dimensionless and composite variable. In general, any
phenomenon that causes a distortion of the flow lines from the perfectly normal to the
well direction or a restriction to flow (which could be viewed as a distortion at the pore-
throat scale) would result in a positive value of the skin effect.
A positive value of the skin effect does not mean that a formation damage exists, but
may indicate a restriction to flow such as partial completion, inadequate number of
perforations, phase change, turbulence or a combination of all of them.

Altered zone
-
Pr

Pwf ΔPskin = Pwf’ - Pwf

Pwf ’

Pwf

ra re
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 Reservoir Model of Skin Effect

Bulk
formation
Altered
zone

ka h k
rw

ra
ka k
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 Reservoir Pressure Profile
2000
Pressure, psi

1500

Pwf ’

1000
ps

Pwf

500
1 10 100 1000 10000
Distance from center of wellbore, ft
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 Skin and Pressure Drawdown

k = Permeability, md
h = Height, ft
q = Production, STB/D
B = Oil Volume Factor, bbl/STB
ps = Pressure drawdown, psi
 = Oil Viscosity, cp

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 Radial Production and Skin
(Darcy’s Law)
q = Production, STB/D
k = Permeability, darcy
h = Height, ft
k h Pr  Pwf  Pr = Reservoir Pressure, psi
q
  re   Pwf = Bottomhole Flowing Pressure, psi
141.2  BO ln    s  = Oil Viscosity, cp
  rw   Bo = Oil Volume Factor, bbl/STB
Ln = natural logaritm
re = drainage radius, ft
rw = wellbore radius, ft
s = skin factor

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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 Concept (Van Everdingen and Hurst)

141.2qBμ  re s
pe  p wf   ln  ln e 
kh  rw 
141.2qB μ  re 
p e  p wf   ln s

kh  w r e 

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 Effective Wellbore Radius

Bulk
formation
Altered
zone

ka h k
rw

ra
ka k

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 Effective Wellbore Radius
Hydraulic Fractured Well

rwa
rw
rwa  rwe  s

For example,

rw = 0.4 ft
s = -3

Rwa = 8 ft

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 Components of “Skin” factor

S = Strue damage + spseudo damages

(Geometric Skin Factors)

S = Sd + Spp + Sp + Ssw + Sgp + Sturb

where:
 Sd = skin due to alteration of permeability in the near
wellbore area (true damage)
 Spp = skin due to partial completion
 Sperf = skin caused by perforating
Pseudo-damages or
 Ssw = skin due to deviated wellbore Pseudo skin factors
 Sgp = skin caused by gravel packs
 Sturb = skin due to turbulent flow

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 Pseudo Skin - Partial Penetration (Spp)
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.

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 Damaged Zone Around Perforation Tunnel

15
(mm)

10
Distance(mm)

5
RadialDistance

0
-5
Radial

-10

-15

15 mm = 0.6 inches = 0.05 feet

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 Pseudo Skin – Perforating (Sp)
Perforating is not a clean operation, even if it is executed underbalance. There always remain a
crushed and compressed zone around the perforating tunnel as well as debris from the charge,
which reduce the original permeability causing additional pressure drops.

Invaded zone Bulk Formation

Compacted Perforating
Zone debris

Cement
Casing

Sp = from Ott & Locke’s Monograph

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 Pseudo Skin - Perforation (Sp)
Sp  SH  SV  Swb
lperf/4 For  = 0
Calculation of SH
r´w() =
SH  ln rw a (rw + lperf ) For  = 0
r ' w( )

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 Pseudo Skin - Perforation (Sp)

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 Pseudo Skin - Perforation (Sp)
Calculation of SV

h rperf  kv 
hD  kh rD  1
kh 
perf
lperf kv 2hperf 
a  a1 log rD  a2
b  b1rD  b2

b 1
SV  10 hD rD a b

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 Pseudo Skin - Perforation (Sp)
Calculation of Swb

rw
rwd 
l perf  rw

S wb  c1e c2 rwD

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 Pseudo Skin – Perforating (Sp)
LOCKE’S NOMOGRAPH FOR SP CALCULATION

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 Pseudo Skin - Deviated Wellbore (Ssw)
In highly deviated wells it also occurs the convergence of flow lines, causing a
positive Skin effect.

rw

h


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23
 Gravel Pack Skin (Sgp)

Cement

sgp - skin factor due to Darcy flow through gravel

pack
h - net pay thickness
kgp - permeability of gravel pack gravel, md
Gravel kR - reservoir permeability, md
Lg - length of flow path through gravel pack, ft
n - number of perforations open
rp - radius of perforation tunnel, ft

Does not include effects of non-Darcy

flow (high-rate gas wells)

Lg
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Effect of Skin on Reservoir Inflow Performance

Inflow
(IPR)
Pressure at Node

Outflow

SKIN
10 5 0 -1 -3

Flowrate
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 True Formation Damage (Sd)

The term Sd represents the true formation damage which can be caused by the
following mechanisms:

1. Plugging of the pore spaces by solid particles.

2. Mechanical crushing or disaggregation of the porous media.

3. Fluids effects such as creation of emulsions or changes in relative permeability.

These mechanisms can result from many sources such as:

1. Formation damage induced during the operations (well drilling and subsequent well
interventions).

2. Formation damage caused during the active production life of the well (scale and
asphaltene precipitation, fines migration, relative permebility changes, condensate
blockage and growth of bacterias).
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 Formation Damage Characterization

 Fines Migration  Induced Particles

 Swelling Clays – Solids
– LCM/Kill Fluids
 Scale Deposits
– Precipitates
 Organic Deposits
 Oil Based Mud
– Paraffins
– Asphaltenes  Emulsion Block
 Mixed Deposits  Wettability Changes
 Bacteria  Water Block
 Gas Condensate Block

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 Porosity in a Sandstone

Pore Pore
Throat Pores Provide the
Body Volume to Contain
Hydrocarbon Fluids

Pore Throats Restrict

Fluid Flow

Scanning Electron Micrograph

A porous media is a complex assembly of irregularly shaped mineral grains with void spaces (pores) which are
also irregularly shaped and distributed providing the path way for fluid transport. Scanning Electron Microscope
Photographs have shown the tortuous nature of the pore spaces and the common presence of small particles
called fines. This complicated structure can be idealized as a collection of chambers connected by narrower
openings, the pore throats, which control the permeability of the medium
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 Porosity in a Sandstone

SCANNIG ELECTRON MICROGRAPH OF A POROUS MEDIUM

50 u

1 u = 0,001 mm Pore body

Pore throat
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 FINES MIGRATION

Fines may be mobilized when

water production begins. Fines
are most likely to move when
non wetting phase
the phase they wet is mobile,
fines and since most formation fines
wetting phase
are water-wet, the presence of
a mobile water phase can
non wetting phase
cause fine migrations.

Migrating fines can bridge pore

throats and restrict fluid
non wetting phase movement causing formation
damage

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 Migrating Clays: Kaolinite
Al2Si2O5(OH)4
Surface of Oxygen

H
Hydroxil Group

Layers Hydrogen Bonded

Kaolinite particles are composed of many

layers stacked one at the top of the
other. Forces binding the layers are
hydrogen bonds sufficient to prevent
water penetration between layers. For
that reason is classified as a non swelling
clay

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 Fines Migration

Fines that originally line the

pore walls in a non-damaging
manner may become
fines: V entrained in the fluid if the
fluid velocity exceeds a
critical value.
Particles can also migrate
with the produced fluids
during normal production.
When the damaging particles
come from the reservoir rock,
they are usually referred to
as formation fines. This term
includes clays and silts.
These particles are soluble in
hydrofluoric acid.

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 Indicators of Fine Migration

 Produced water may be turbid

 Production decline increases with increasing flow rate.
 Clays and silica fines are insoluble in HCl.

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 FINES MIGRATION

CRITICAL VELOCITY
c
DETERMINATION IN THE LAB

Uc

P
L

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 Swelling Clays: Smectite (Montmorillonite)
Na0,33 Al1,6 Mg0,33 Si4 O10 (OH)2

Water from external sources like drilling,

completion, workover or treating fluids
can enter between the unit layers
disturbing the equilibrium between clays
and formation water, causing the
expansion of the clay
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 CLAYS STABILIZATION

Treatment:

Hydrofluoboric Acid (HBF4) also known as

CLAY ACID

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 Scale

Mechanism of Scale Deposition

Scale deposition can occur whenever the mineral saturation
exceeds the critical equilibrium saturation. The solution
becomes supersaturated in the particular mineral. A super-
saturated solution is defined as a solution containing a high
concentration of dissolved solute than the equilibrium
concentration. When the solution is supersaturated,
minerals will then precipitate out of the solution. Factors that
cause the solution to become supersaturated are changes in
pressure, temperature, pH and mixing of incompatible fluids.

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 Scale

Inorganic mineral deposits

CAUSES:
 OVERSATURATED SOLUTION BY INCOMPATIBLE FLUIDS
 ALTERATION OF THE THERMODYNAMIC EQUILIBRIUM BY CHANGES IN
PRESSURE AND TEMPERATURE
 IONS EXCHANGE
• COMMON TYPES ARE:
 CaCO3
 CaSO4
 SrSO4
 BaSO4

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 Solubility of Various Minerals

Scale Solubility mg/liter

Sodium Chloride 318,300.0
Calcium Sulfate 2,080.0
Calcium Carbonate 53.0
Barium Sulfate 2.3

(in Distilled Water)

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 Solubility of Various Minerals
Solubility of minerals as a function of Pressure
Barium Sulphate, lbm/bbl

Temperature, oF
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 Scale

 Form in the plumbing system of the well, in the

perforations/near wellbore formation.

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 Organic Deposits -Paraffins

• Linear or branched-chain saturated aliphatic

hydrocarbons
C20H42 to C60H122

• Cloud point: temperature at which first fraction

precipitates
• Pour point: temperature at which fluid gels

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 Factors Accelerating Paraffin Precipitation
Paraffins
 Precipitate upon cooling and pressure reduction.
 Soluble in aromatic solvents (Xylene, Toluene).

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 Organic Deposits -Asphaltenes
• Aromatic Rings
• High Molecular weight
• Black, sticky to hard solid
• Colloidally dispersed in crude oils
• Colloidal State stabilized by the presence of resins

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 Factors Accelerating Asphaltene Flocculation

 Resins removal by the addition of

paraffinic crude, water, acid or CO2
 pH effects (low or high pH fluids
destabilizes the colloidal status)
 Pressure decrease below bubble
point pressure (liberation of light oil
components)
 Remix of oil with a different gas
composition from another reservoir
acid  Soluble in aromatic solvents (Xylene,
Toluene).

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 Mixed Deposits

 Blend of organic compounds and either scales, silts, or

clays.

• Strip organic phase with an organic solvent (Xylene) and

dissolve inorganic material with proper solvent

• Usually require a dual-solvent system (e.g. Xylene

followed by HCl).

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 Bacteria
 Bacteria are naturally present in many parts of a petroleum
producing operation.

 They can multiply rapidly under broad ranges of conditions,

causing plugging or fouling of reservoirs or equipment.

 Bacteria metabolize (or eat) the hydrocarbons found in the well.

 They are typically classified by whether they utilize oxygen as the

energy source for growth. Aerobic bacteria need oxygen, while
anaerobic bacteria do not.

 Facultative bacteria can change their metabolism so they are able

to grow in either environment. However, they will generally grow
much faster (by a factor of 5) if oxygen is present.
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 Bacteria
Bacteria which can cause formation damage include:

Sulfate-Reducing Bacteria (SRB): These bacteria use sulfate ions

to provide energy for growth and are therefore anaerobic. They
reduce the sulfate ions to sulfide ions, generating hydrogen sulfide
(H2S) as a by-product. If large colonies of these bacteria form, this
process can lead to pitting corrosion as the corrosive H2S is
formed in a concentrated spot. The H2S can also increase the
corrosivity of the produced waters and lead to sulfide cracking
problems. Large amounts of bacteria can cause plugging
problems..

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 Bacteria
 Iron bacteria: These bacteria convert iron from the ferrous (Fe 2+)
to the ferric (Fe 3+) state, forming a sheath of gelatinous ferric
hydroxide around themselves. The bacteria can utilize dissolved
iron in the formation water at concentrations as low as one ppm.
The ferric hydroxide is highly insoluble and precipitates out of the
formation fluids..

 Slime formers: These types of bacteria can produce dense

masses of slime causing corrosion and plugging problems. They
prefer low-salinity waters and are anaerobic.

 Bacteria damage is typically found in water-injection wells,

disposal wells or geothermal wells.

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 Drilling Fluid Damage

Mud Solids
and Filtrate
Invasion

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 Solids Invasion

The effectiveness of the bridging material in a drilling mud, mainly depends on the geometry of
the porous medium, more specifically on the shape and size distribution of the pore throat, as
compare with the size and shape of the bridging particles.

Bridging
particles

Mud Formation
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Solids Invasion

Effective external cake Pore-throat 10 microns

Solids between 1 and 3 microns

Pore-throat 10 microns
Internal cake
Solids ≤ 1 micron

Pore-throat 10 microns
Ineffective Solids 10 microns and others
External cake less than 10 microns (nonuniform
Size distribution)

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 Drilling Damage

Drilling Mud Solids Invasion is favored by:

 Large pore size of the formation rock

 Non uniform mud particle size distribution
 Small mud particle size from weighting agent and LCM
 Presence of fissures and natural fractures in the reservoir
 High pressure overbalance
 High drilling rate (mud cake destruction  loss of circulation)
 Low drilling fluid circulation (long mud to formation contact time)

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 Drilling Damage
Filter cake Formation
 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!

RDF (STARDRILL) Filter Cake

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 Drilling Damage

Mud Filtrate Invasion Damage

 Changes in relative permeability

 Water Blockage
 Changes in wettability
 Emulsions
 Minerals, 0rganic and inorganic precipitation
 Fines Migration
 Clay Swelling

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 Drilling Damage

Mud Filtrate Invasion is favored by:

High permeability of the mud filter cake, a result of either

poor drilling fluid design or detrimental drilling procedures.
High overbalance.
Long formation-to-drilling fluid contact time.

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 Drilling Damage
Oil Base Mud
The numerous drawbacks of water-based drilling fluids led to the development of oil-based
mud for drilling through clay and sandstones.
It is recognized, however, that although the problems of oil-based mud are less numerous
than those of water-based mud, they are often much more severe. Usual drawbacks include:

 oil based mud contain more solids than water-based mud. Consequently, particle invasion
is more pronounced.
 oil that invades gas reservoirs, especially tight ones, causes sharp reductions in relative gas
permeability (more problematic than water invasion because of the viscosity of oil).
 strong oil-wetting surfactants used to disperse solids in oil-based mud convert formation
rocks into an oil-wet state. This significantly reduces the relative permeability to oil.
 cationic emulsifiers used to stabilize water-in-oil emulsion mud also stabilize in-situ
emulsions that already tent to build up inside oil-wet porous media. Strong emulsion blocks
can occur in sandstone reservoirs, especially in those of low permeability and high clay
content.

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 Cementing
Washes & spacers
During the mud-removal process the mud cake can be partially destroyed, and
if these cement pre-flush fluids do not possess the right fluid-loss properties,
formation rocks may be less protected against filtrate invasion. This invasion
may be increased when high pressure differentials are set (cementing under
turbulent flow).

Cement slurries
Calcium ions liberated by cement particles are very quickly exchanged on clays
near the wellbore.
Cement filtrate which comes into contact with connate brines that contain high
concentrations of calcium can provoke precipitation's of calcium carbonate,
lime, or calcium silicate hydrate.

Squeeze
High pressures used for squeezing cement are thought to cause formation
fracturing and slurry invasion.

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 Completion Fluids Damage

 Suspended Solids  Fluid Loss Control

– Polymer Residue – Formation Sensitivity
– Clays
– Wettability
500
– Scales
A (2.5 ppm)
(A) Bay Water Filtered
Permeability (md)

Through 2um Cotton Filer

100
(B) Bay Water
Through 5um Cotton Filter
B (26 ppm)
(C) Produced Water Untreated
50
C (94 ppm)
(D) Bay Water Untreated
D (436 ppm)

10
0 0.02 0.04 0.06 0.08 0.10

Volume Injected (gal/perf)

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Injection Operations

Water Injectors
 Suspended solids invasion and subsequent plugging.
 In-situ clay disturbance.
 Scales formed from mixing incompatible injection and formation
waters
 Plugging by bacterial residues is also developed in water injection
wells.

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Injection Operations

Common Problems in Water Injection/Disposal Wells

1. Formation of an external cake

2. Solids invasion and formation of an internal cake
3. Plugging of perforation tunnels by solids
4. Progressive plugging of the perforated interval by solids settling at
the bottom hole

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Injection Operations
SUSPENDED TRAPPED SOLIDS MECHANISMS
(Water Injection)

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Emulsions
TYPES OF EMULSIONS

WATER OIL
EMULSION OF OIL IN WATER EMULSION OF WATER IN OIL

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 MECHANISMS OF EMULSIONS FORMATION IN THE POROUS MEDIUM

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 Effect of Wettability on relative permeability curves

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 Water Block Damage

1 1
 A reduction in effective or
Water Wet
relative permeability to oil due to Oil Wet
increased water saturation in Kro
Kro Krw
the near wellbore region. Krw

 Treatment: Reduction of
interfacial tension using
surfactants/alcohol's in acid
carrier
0
0 Swc 1-Sor 1
Sw

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 Gas Blockage

 In an oil reservoir, pressure near

well may be below bubblepoint,
allowing free gas which reduces
effective permeability to oil near
wellbore.
p < pb p > pb  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.

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 Formation Damage Characterization

 Classifying damage correctly requires more

than a little experience, and a thorough
knowledge of field operating conditions.
 Correct identification is critical to successful
removal of the damage or other impairment.
 Well history is essential to determining the
source of formation damage.
 Understanding when the formation damage
occurred will lead to correctly determining the
type of formation damage.

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 Formation Damage Removal

 Maxtrix acidizing is a common treatment for damages

such as
• Fines Migration
• Swelling Clays
• Induced Particles
 Non-acid fluids may be used to treat damages such as
• Organic Deposits
• Bacteria
 Some damages can be treated with either type of fluids
or combinations of fluids
 Scales typically occur in the wellbore so wellbore rather
than matrix treatments are used for this damage type

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