Formation DamagePractical

1.

PETROLEUM PRODUCTION TECHNOLOGY
AND TECHNIQUE
Formation
Damage
and Skin
Week 9
Practical class

2.

Formation damage and near-wellbore flow
Main damage mechanisms
Completion and workover effects
Skin factor and the Hawkins model
Productivity and potential production gains
Diagnosis and prevention of formation damage
Practical cases: calculations and treatment selection
Week 9 Formation Damage and Skin
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3.

Formation damage and near-wellbore flow
Radial flow crosses the altered zone
A small volume near the well can
create a large part of the pressure
loss.
Damage thickness = rd − rw
Week 9 Formation Damage and Skin
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4.

Permeability and phase mobility
Effective permeability
keff,i = k × kri
keff,i — effective permeability to phase i when other immiscible phases
are present (mD).
k — absolute permeability of the rock, measured when only one fluid
phase is present (mD).
kri — relative permeability to phase i (dimensionless).
i — phase index: o = oil, w = water, g= gas.
Week 9 Formation Damage and Skin
Phase mobility
λi = k × kri /μi
λi — mobility of phase i (mD/cP)
μi — dynamic viscosity of phase i (cP)
04

5.

Solids plugging and fines migration
Introduced solids
Particles from drilling, completion or
injection fluids can lodge in pore
throats.
Migrating fines
Native particles detach, move with the
fluid and accumulate at constrictions.
Week 9 Formation Damage and Skin
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6.

Clay sensitivity to injected water
Clay swelling
Sensitive clays such as smectite can
hydrate and expand.
Fines migration
Particles detach, move with the fluid and
lodge at pore throats.
Water chemistry
Mineralogy, salinity, ionic composition and
pH affect the response.
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7.

Emulsions and wettability
φ = water volume fraction in the emulsion.
Emulsion formation
Wettability alteration
Dispersed droplets can increase apparent flow
resistance.
Changes phase distribution and relative
permeability.
Week 9 Formation Damage and Skin
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8.

Inorganic scale deposition
Formation or perforation scale
Precipitates can restrict inflow.
Tubing scale in the photograph
The reduced bore restricts outflow.
Treatment follows chemistry
CaCO₃ and BaSO₄ require different
dissolution strategies.
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9.

Wax and asphaltene deposition
Wax crystallisation
Cooling below the wax appearance
temperature.
Week 9 Formation Damage and Skin
Asphaltene instability
Changes in pressure, temperature or
composition.
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10.

PRACTICAL CASE 1
Case 1. Rate decline and well productivity
Oil rate falls by half. Has inflow performance deteriorated?
Measurement
Before
After
Reservoir pressure, psi
3500
3000
Flowing bottomhole pressure, psi
2500
2500
Oil rate, STB/day
500
250
Calculate drawdown and J for each date. Explain the rate decline.
Week 9 Formation Damage and Skin
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11.

PRACTICAL CASE 1
Case 1. Interpretation
Before
After
J = 500 / 1000
= 0.50 STB/day/psi
J = 250 / 500
= 0.50 STB/day/psi
Unchanged productivity. Lower drawdown explains the lower rate.
Next action: confirm pressure depletion and assess drawdown and lift options.
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