06 formation damage

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Formation Damage

Types of Damages and Origins, Skin Factor and Productivity Index, Flow Efficiency

Copyright 2007, , All rights reserved 2

Origin of Formation Damage

Formation damage – Types– Origin– Location

Diagnosis Removal and Prevention

– Methods– Chemistry


Formation Damage Characterization

Fines Migration Swelling Clays Scale Deposits Organic Deposits

– Paraffins– Asphaltenes

Mixed Deposits Bacteria

Induced Particles– Solids– LCM/Kill Fluids– Precipitates

Oil Based Mud Emulsion Block Wettability Changes Water Block


Swelling Clays: Smectite


Migrating Clays: Kaolinite

Copyright 2007, , All rights reserved

FINES MIGRATION MECHANISMFINES MIGRATION MECHANISM

fineswetting phase

non wetting phase

non wetting phase

non wetting phase


Scale

Inorganic mineral deposits. Formed due to supersaturation at wellbore conditions or

commingling of incompatible fluids. Form in the plumbing system of the well, in the

perforations/near wellbore formation.


Drilling Fluid Damage

Mud filtrateinvasion


RDF (STARDRILL) Filter Cake

Filter cake Formation

Drilling Damage

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!


Drilling Damage

Drilling Mud Solids– Particle Size vs. Pore

Size/Fissures– Filtration - 3 inches– Poor Mud Cake– Overbalance

Drilling Mud Filtrate– Formation Sensitivity (pH,

salinity, scale)– High Penetration Capillarity– Fines Dispersion– Additive Residues– Cooling

Oil Based Muds– High Solids Oil – Invasion/Relative Permeability– Cationic Emulsifiers


Perforations

Debris Compacted Zone

Rad

ial

Dis

tan

ce (

mm

)


Completion Fluids Damage

Suspended Solids– Polymer Residue

Fluid Loss Control– Formation Sensitivity– Clays– Wettability– Scales

A (2.5 ppm)

C (94 ppm)

D (436 ppm)

Per

mea

bili

ty (

md)

Volume Injected (gal/perf)

500

100

50

100 0.02 0.04 0.06 0.08 0.10

(A) Bay Water FilteredThrough 2um Cotton Filer

(B) Bay Water Through 5um Cotton Filter

(C) Produced Water Untreated

(D) Bay Water Untreated

B (26 ppm)


Water Block Damage

A reduction in effective or relative permeability to oil due to increased water saturation in the near wellbore region.

Favored by pore-lining clay minerals (Illite)

Treatment Þ Reduction of interfacial tension using surfactants/alcohol's in acid carrier

1 1

Kro Krw

0

0 1Swc 1-SorSw

Water Wet

Oil Wet

Kro

Krw


Damage due to Production

In an oil reservoir, pressure near well may be below bubblepoint, allowing free gas which reduces effective permeability to oil near wellbore.

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.

p < pbp > pb

The main Production damage is due to Fines Migration


Damage Quantification

The Damage is quantified by the Skin Factor and the Productivity Index


Reservoir Model of Skin Effect

Bulkformation

h

rw

ka

ra

Alteredzone


Reservoir Pressure Profile

Distance from center of wellbore, ft

500

1000

1500

2000

1 10 100 1000 10000

Pre

ssu

re, p

si

ps


Skin and Pressure Drawdown

k = Permeability, mdh = Height, ftq = Production, STB/DB = Oil Volume Factor, bbl/STBps = Pressure drawdown, psi = Oil Viscosity, cp


Radial Production and Skin

q = Production, STB/Dk = Permeability, darcyh = Height, ftPr = Reservoir Pressure, psiPwf = Bottomhole Flowing

Pressure, psi = Oil Viscosity, cpBO = Oil Volume Factor, bbl/STBln = natural logaritmre = drainage radius, ftrw = wellbore radius, fts = skin factor

(Darcy’s Law)

srr

lnB141.2

PPhkq

w

eO

wfr


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.


Effective Wellbore Radius


Geometric Skin – Converging Flow to Perforations

When a cased wellbore is perforated, the fluid must converge to the perforations to enter the wellbore. If the shot spacing is too large, this converging flow results in a positive apparent skin factor. This effect increases as the vertical permeability decreases, and decreases as the shot density increases.


Geometric Skin - Partial Penetration

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.

h

hp


Partial Penetration

hp

ht

h1


Geometric Skin - Deviated Wellbore

sechh

S


Geometric Skin - Well With Hydraulic Fracture

rw

r’w

sww err '

For example,

rw = 0.4 fts = -3

rw’ = 8 ft


Completion Skin

rdp

Lp

kR

kdp

kd

rp

rd

rw

After McLeod, JPT (Jan. 1983) p. 32.

sp- geometric skin due to converging flow to perforations

sd - skin due to formation damage sdp - perforation damage skinkd - permeability of damaged zone around wellbore,

mdkdp - permeability of damaged zone around

perforation tunnels, mdkR - reservoir permeability, mdLp - length of perforation tunnel, ftn - number of perforationsh - formation thickness, ftrd - radius of damaged zone around wellbore, ftrdp - radius of damaged zone around perforation

tunnel, ftrp - radius of perforation tunnel, ftrw - wellbore radius, ft


Gravel Pack Skin

Lg

Cement

Gravel

sgp - skin factor due to Darcy flow through gravel packh - net pay thicknesskgp - permeability of gravel pack gravel, mdkR - reservoir permeability, mdLg - length of flow path through gravel pack, ftn - number of perforations openrp - radius of perforation tunnel, ft

Does not include effects of non-Darcy flow (high-rate gas wells)


Productivity Index

The productivity index is often used to predict how changes in average pressure or flowing bottomhole pressure pwf will affect the flow rate q.

The productivity index is affected by– Reservoir quality (permeability)– Skin factor


Flow Efficiency

We can express the degree of damage on stimulation with the flow efficiency.For a well with neither damage nor stimulation, Eff = 1.

For a damaged well, Eff < 1

For a stimulated well, Eff > 1

wf

swf

ideal

actualff pp

Δppp

J

JE

06 formation damage

Documents

reduces effective permeability

vertical permeability decreases

gravel pack

effect increases

converging flow

skin factor

wetting phase

md kr