C5 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 nearwellbore 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.

Đỗ Quang Khánh – HoChiMinh City University of Technology

Email: dqkhanh@hcmut.edu.vn or doquangkhanh@yahoo.com

Designed & Presented by

Mr ĐỖ QUANG KHÁNH, HCMUT

1

What is Formation Damage?

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

rather than stimulation to overcome limited productivity

Sources of Formation Damage

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

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

FLOW

ENTRAINMENT DEPOSITION

Bridging

TYPICAL HYDRAULIC TUBE

Straining

Solid particles

Bridging Mechanism

Flat bridges Arch bridges No bridges

(after Valdes and Santamarina, 2006)

Bridging of Particles at Perforation

Maximum Gravel Content – LB/GAL

Pore-to-particle diameter ratio

Particle-Volume-Fraction Reynolds number

(Tran et al 2009, SPE 120847)

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

Near Wellbore Area

 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

p s

p wf, real

p wf, ideal

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

damage zone (r s ) and wellbore (r w )

 Real case (damage zone with permeability of k s )

Math Development of Damage Skin

 Skin effect defined as additional steady-state pressure drop

in the near-wellbore region

Hawkins’ Formula – Skin Factor

 Since difference between ideal and real wellbore pressure is

due to skin effect:

Hence

 Solving for s:

Another Derivation of Skin

Example: Permeability Impairment

Versus Damage Penetration

A well with radius rw equal to 0.328 ft and damage penetration 3 ft

beyond well (rs= 3.328 ft)

1) What is skin effect if permeability impairment results in k/ks = 5

and 10, respectively?

2) What would be the required damage depth to give same skin as

with k/ks=10 but the actual permeability impairment being k/ks = 5?

Solution

1) From Hawkins formula, calculate skin for each permeability

impairment:

2) Since skin is 20.9 for k/ks = 10 and using k/ks = 5, re-arrange

Hawkins’ formula for damage penetration:

For k/ks = 5 For k/ks = 10

Rate Dependent Pseudo Skins ΣS pseudo

 The pseudo-skins include all phase and rate dependent effects

 Turbulence in high-rate gas procedures ( affect very high-rate oil wells)

 This skin effect is equal to Dq

Phase Dependent Skin ΣS pseudo

• Flowing bottomhole pressure is below the bubble point

pressure, in the case of oil wells

• Liquid formation around the well, in the case of gas

retrograde condensate reservoirs

 Relative Permeability effects

Partial Penetration Skin S c+ ϴ

Sc+ ϴ = Sc + Sϴ

 Skin due to partial completion Sc

 Skin due to well deviation Sϴ

 Perforated height < reservoir thickness

 Effect becomes negligible when completion height > 75% of reservoir

thickness

Partial Penetration Skin S c+ ϴ

 z w : elevation of the perforation midpoint from the base of the reservoir

 hw : perforated height

 h:reservoir height

 r w : well radius

 θ: angle of well deviation

Cinco-Ley et al – 1975: Tables 1 and 2

Partial Penetration Skin S c+ ϴ

Partial Penetration Skin S c+ ϴ

Ex: Partial Penetration Skin S c+ ϴ

reservoir In order to avoid severe water coning problems, only 8

ft are completed and the midpoint of the perforation is 29 ft

above the base of the reservoir Calculate the skin effect due to partial completion for a vertical well What would be the

composite skin effect if θ =45deg ?

Skin effect due to Partial Completion

Skin effect due to Slant wells

Perforation Skin S p

the horizontal skin (Sh ), the wellbore skin (Swb ), the vertical skin (Sv ) &

the crushed zone skin (Sc )

Perforation Skin S p

 the horizontal skin (Sh ):

 the wellbore skin (Swb ):

 the vertical skin (Sv ):

 the crushed zone skin (Sc )

 =>This allows the calculation of the overall skin for the

Perforation Skin S p

terminates inside the damaged zone or not

 For perforations terminating inside the damaged zone (lp < ld )

 For the (hopefully) more

relevant case of perforations that

extend beyond the damage zone

(lp>ld), the perforation length and

wellbore radius are modified:

Ex of Perforation Skin S p

 Ex: