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C5 formation damage

Designed & Presented by

Mr. ĐỖ QUANG KHÁNH, HCMUT

Đỗ Quang Khánh – HoChiMinh City University of Technology
Email: dqkhanh@hcmut.edu.vn or doquangkhanh@yahoo.com

1


What is Formation Damage?
 Damage can be anything that obstructs the normal flow of fluids
to the surface.
 Formation damage specifically refers to obstructions occurring in

the near-wellbore region of the rock matrix.=> Concerns the
formation of a volume of rock with a reduced permeability in the

near wellbore zone.
 Ultimate economics usually favor control of formation damage
rather than stimulation to overcome limited productivity.



Sources of Formation Damage
 Damage during drilling operations

 Damage during completion operations

 Damage during well stimulation

 Damage caused by other operations


Damage during drilling operations


Mud solids may block pores, vugs, and natural or induced fractures.



Mud filtrate invasion into oil and gas zones may oil-wet the formation and cause water or
emulsion blocks.



Pore or fractures near the wellbore may be sealed by the trowelling action of the bit, drill collars
and drill pipe.



Cement or mud solids may plug large pores, vugs, and natural or induced fractures.



Chemical flushes used to scour hole ahead of cement may cause changes in clays in the
producing formation.



Filtrate from high fluid loss cement slurries may bring about changes in the producing formation.



Damage during completion operations
 Damage during perforating



Perforations may be plugged with shaped charge debris and solids from perforating fluids.
Formation around perforation is crushed and compacted by perforating process.

 Damage while running tubing and packer



If returns are lost while running tubing, solids in the well fluid may plug any fracture system near the
wellbore
Perforations may be plugged if solids are forced into perforations by the hydrostatic differential
pressure into the formation.

 Damage during production initiation





Damage may be caused by incompatible circulation fluids and by loss of clays or another fines into
perforation pores, vugs.
Damage may result from depositing of mill scale, clay, or excess thread dope from tubing collars in
perforation when circulating to clean a well.
Completion fluids containing blown asphalt may cause damage by oil-wetting the formation and by
plugging perforations and formation.
Clean-up of a well at high rates can result in severe plugging within the formation by particles which,
for one reason or another, are free to move.


Damage during well stimulation


Perforations, formation pores, and fractures may be plugged with solids while killing or circulating a
well with mud or with unfiltered oil or water.



Damage may be caused by filtrate from circulating fluids.



Breaking down or fracturing the formation with acid may shrink the mud cake between the sand face
and cement or may affect mud channel in the annulus allowing vertical communication of unwanted
fluids.



Acidizing sandstone with hydrofluoric acid may leave insoluble precipitates in formation. Properly
designed treatment minimizes effect.



Damage may be caused by hydraulic fracturing fluids.



Damage may be caused by incompatible fluid in fracture acidizing of carbonates.


Damage caused by other operations
 Damage caused by cleaning of paraffin solids from the tubing, casing, or wellbore

 Damage during well servicing or workover

 Damage during producing phase

 Damage during water injection

 Damage during gas injection


Common Formation Damage Mechanisms
 1. Fines invasion and migration (particles, etc.)

 2. Rock-fluid incompatibility (clay swelling, etc.)
 3. Fluid-fluid incompatibility (emulsion generation, etc.)
 4. Phase trapping and blocking (water entrapment in gas reservoirs)

 5. Adsorption and wettability alteration
 6. Biological activity (bacteria, slime production).


Particle Plugging within the Formation
 The pore system provides a tortuous path to the wellbore

 Particles can move through the pore system.

 Particle movement is affected by wettability and by the fluid
phases in the pore system.


Particulate Capture Mechanisms

Straining

Bridging

DEPOSITION
ENTRAINMENT

FLOW
Solid particles

TYPICAL HYDRAULIC TUBE


Bridging Mechanism

Flat bridges

Arch bridges

(after Valdes and Santamarina, 2006)

No bridges


Perforation Diameter
Average Particle Diameter

Bridging of Particles at Perforation
No Bridging

well

6

bridging
4

Bridging Region
2

perforation

4

8

12

16

20

24

28

Maximum Gravel Content – LB/GAL

(After Gruesbeck and Collins, 1982)

32


Exponential-law equation
  A 1  exp   B Re p   C
 A, B, and C are empirical parameters
  A 1  exp   B Re p   C

Pore-to-particle diameter ratio
6

D
  T
Dp



Particle-Volume-Fraction Reynolds number

Re p 

 p p vDp


4

Bridging Region

2

4

8

12

16

20

Rep

(Tran et al. 2009, SPE 120847)

24

28

32


Formation Clays (Inherent Particles)
 Oil-producing sandstones contain clays as a coating on
individual sand grains. (clean sand contains 1-5% clay, dirty
sand contains 5 to greater than 20% clay)

 Common clays: smectite (bentonite), illite, mixed-layer clays
(primarily illite-smectile), kaolinite, and chlorite.


Clay Migration
 Clay migrate when contacting with foreign water which alters the
ionic environment.
 Foreign waters are filtrate loss from drilling fluids, cement,

completion fluids, workover fluids, and stimulation fluids.
 Other effects: swelling due to hydration cations, cation type and

concentration, and pH.


Diagnosis of Formation Damage
 Determine formation damage or skin effect in a particular
well.
 Analysis of pressure buildup or fall off tests.
 Production logging surveys.
 Comparison of productivity of the subject well with productivities of

surrounding wells.
 Rule out mechanical problems such as sand accumulation in the

wellbore or artificial lift difficulties.


Skin Formulation
 St = ΣSi (Total skin is sum of components)
= Sd + Sc+ ϴ + Sp + ΣSpseudo

 Formation Damage (Sd)


Mechanical damage to near-well formation

 Partial Penetration Skin Sc+ ϴ


Partial completion (Sc)



Slanted (deviated) wellbore (Sdev)

 Perforation Skin (Sd)
 Non-Darcy Flow (Turbulence damage) (ΣSpseudo)


Near Wellbore Area
 Drilling, cementing, and completion alter reservoir conditions near the well.

 Distortion or restriction of flow.

 Additional near wellbore pressure drop - “skin”.

 Characterized with:


Damage permeability, ks



Damage radius, rs


Wellbore Skin Effect
Positive Skin Effect:

denotes that the pressure drop in the near wellbore zone is more
than it would have been, from the normal, undisturbed,
reservoir flow mechanism.


Modifications to IPR

Pwf (no skin)

Pwf (with skin)


Near Wellbore Pressure Drop

pwf, ideal
pwf, real

ps


Positive Skin Effect
Any phenomenon that causes a distortion of the flow lines from the
perfectly normal to the well direction, or a restriction to flow,
would result in a positive value of skin.
 damage to the natural reservoir permeability

 partial completion (distortion of flow lines)
 inadequate number of perforations (distortion of flow lines)
 phase changes (relative permeability reduction to the main fluid)

 turbulence (rate dependent)


Negative Skin Effect
A negative skin effect denotes that the pressure drop in near
wellbore zone is less than it would have been from the
normal, undisturbed, reservoir flow mechanism.
It may be the result of:
 Acid matrix stimulation
 Hydraulic fracturing

 A highly declined wellbore


Math. Development of Damage Skin
 Steady-state pressure drop between outer boundary of
damage zone (rs) and wellbore (rw)
 Ideal case (no damage zone)

 Real case (damage zone with permeability of ks)


Math. Development of Damage Skin
 Pressure drop due to damage:

 Skin effect defined as additional steady-state pressure drop
in the near-wellbore region


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