Formation damage and damage skin

Quick refresher

Formation damage is a reduction in the permeability of the near-wellbore zone. Most of the drawdown is spent there, so even a ring a few centimetres thick can cut the rate by half.
Some mechanisms reduce the absolute permeability: particles of drilling fluid (mud) and cuttings (small pieces of drilled rock), migrating fine particles, swollen clays, salt deposits, asphaltene, resin and paraffin deposits (ARPD, the sticky solids that heavy parts of the oil leave behind), and polymer residues. Others reduce the phase permeability to oil or gas: water and emulsion blocks, and a change in wettability.
The model of a zone of reduced permeability is $S_d = (k/k_d - 1)\ln(r_d/r_w)$ . The degree of reduction enters linearly, and the depth enters through a logarithm. A non-uniform profile is divided into rings, and their skins are added up.
Perforation tunnels that reach beyond the damaged zone almost bypass it. So for a cased well (one lined with steel pipe), shallow damage is better even if it is severe. For an open hole (no pipe in the reservoir section) the damage should be as mild as possible.
We recognise damage from productivity below the expected value, from the skin found in well testing (after we subtract the pseudo-skins, the extra resistances that are not damage), from the inflow profile (how much each interval produces) and from the history of operations. For an acid treatment we need to know the type and place of the damage. For hydraulic fracturing we need to know only that it exists.
Prevention is cheaper than cure: a small overbalance (well pressure above the reservoir pressure), drilling fluids with particles of chosen sizes, filtrates (the liquid that leaks from the fluid into the rock) that are compatible with the reservoir, and clean kill fluids (also called workover fluids: the heavy fluids that hold a well still during repairs).

Key relationships

S_d = \left(\dfrac{k}{k_d} - 1\right)\ln\dfrac{r_d}{r_w}

skin of one zone of reduced permeability (Hawkins formula)

S_d = \sum_i \left(\dfrac{k}{k_i} - 1\right)\ln\dfrac{r_i}{r_{i-1}},\quad r_0 = r_w

several concentric zones

\dfrac{q_d}{q_0} = \dfrac{X}{X + S_d},\quad X = \ln\dfrac{r_e}{r_w} - \dfrac34

the share of the rate that a damaged well keeps at the same drawdown (pseudo-steady-state flow, in which the pressure falls at the same pace everywhere in the drainage area)

Common pitfalls

Mixing up the damage skin with the total skin. Acid does not remove the pseudo-skins of partial penetration, perforation and inertial losses.
Averaging the permeability of the damaged zone arithmetically over the thicknesses. A thin, badly damaged layer at the wall decides almost the whole skin.
Comparing the depth of damage with the length of the perforation tunnels from surface tests of the charges. In the reservoir the tunnels are shorter.
Treating a well with acid without knowing the nature of the damage. Acid does not dissolve barium sulfate, for example, and it can itself cause deposits and emulsions.

After this lesson you can

explain why damage even in a thin zone around the wellbore (the drilled hole) cuts productivity strongly, and how the damage skin differs from the other components of skin
tell the damage mechanisms apart by what they reduce: absolute permeability (the permeability when one fluid fills the pores) through plugging, swelling and deposits, or phase permeability (the permeability to one fluid when other fluids share the pores) through water and emulsion blocks and a change in wettability (which fluid the rock surface prefers to touch)
calculate the damage skin from the model of a zone of reduced permeability, including a profile of several zones, and estimate the loss of rate
explain how the ratio of the depth of damage to the length of the perforation tunnels (the channels that the shots make in the rock) affects the choice of drilling fluid and of the way to complete the well (prepare it for production)
list the ways to recognise damage and to choose between preventing it, removing it and bypassing it

What damage is and why it costs so much

In radial inflow (flow from all sides towards the well), the flow converges on the wellbore. The flow velocity and the pressure gradient (how fast the pressure changes with distance) are highest at the wall. So most of the drawdown is spent in the first few metres around the well (see the lesson on permeability and the lesson on the skin factor). That is why a drop in permeability right there has a much stronger effect on the rate than the small size of the zone suggests. We call it formation damage. In Russian-language practice it is also called contamination of the near-wellbore zone.

Damage is not caused by drilling alone. Almost any operation during the life of a well can make the reservoir worse. The list includes cementing (fixing the casing in the hole with cement), perforating, installing screens with a gravel pack (a filter against sand), killing the well (stopping it with a heavy fluid), repair work, production, and water injection. It even includes treatments that are meant to improve the reservoir. The sources of damage at each stage are covered in detail in the lesson Sources of formation damage. Here we look at how damage is arranged in the pores, how to express it as a number, and what to do about it.

The extra pressure drop near the wellbore has to be paid for with a lower rate or a larger drawdown. A damaged well takes longer to earn back its cost. It needs artificial lift sooner. When operating costs are high, it reaches its economic limit (the point where running the well no longer pays) sooner, and it leaves part of the oil and gas unproduced in the reservoir. It can be worse still. A badly damaged low-permeability gas reservoir may give no inflow at all, and it may be wrongly declared non-productive.

What happens in the pores

The narrowest places in the pore space limit the flow. These are the pore throats (the narrow channels that join the pores). Every kind of damage, in the end, either narrows and plugs these channels or stops the right phase (oil, gas or water) from moving through them. We use this to divide the mechanisms into two groups.

Plugging and narrowing of the channels: absolute permeability falls

Mechanism: Mud solids and cuttings (pore plugging)
What happens: particles of clay, weighting material (a heavy powder, such as barite, that makes the mud heavier) and drilled rock enter the pores and stick in the channels. They form an internal cake (a layer of packed particles inside the pores at the wall)
When it happens: drilling with overbalance, killing the well with unfiltered fluids

Mechanism: Fines migration
What happens: particles of clay minerals (kaolinite and illite) and of quartz break away from the grains and block the channels, like rubbish in a drain
When it happens: high velocities near the wellbore, the start of water inflow, a change in salinity (how salty the water is)

Mechanism: Swelling of clays
What happens: smectite (a clay mineral that swells) takes in water between the layers of its crystal lattice and grows in volume
When it happens: contact with fresh or incompatible water

Mechanism: Salt deposits (scale)
What happens: calcium carbonate and the sulfates of barium, strontium and calcium come out of the water and settle in the pores
When it happens: a fall in pressure and temperature, mixing of incompatible waters

Mechanism: Asphaltene, resin and paraffin deposits (ARPD)
What happens: paraffin (wax) comes out of the oil when it cools; asphaltenes (the heaviest, sticky part of the oil) come out when the pressure falls or when the oil meets acid
When it happens: production, injection of cold fluids, acid treatments

Mechanism: Polymers and gel residues
What happens: large molecules settle on the pore walls and narrow the channels
When it happens: drilling fluids and fracturing fluids that contain polymers

Mechanism: Compacted zone around the perforation tunnels
What happens: the jet of the shaped charge (an explosive charge that shoots a fast jet of metal) has crushed and compacted the rock, and there is debris in the tunnel
When it happens: perforating, especially with overbalance

Mechanism	What happens	When it happens
Mud solids and cuttings (pore plugging)	particles of clay, weighting material (a heavy powder, such as barite, that makes the mud heavier) and drilled rock enter the pores and stick in the channels. They form an internal cake (a layer of packed particles inside the pores at the wall)	drilling with overbalance, killing the well with unfiltered fluids
Fines migration	particles of clay minerals (kaolinite and illite) and of quartz break away from the grains and block the channels, like rubbish in a drain	high velocities near the wellbore, the start of water inflow, a change in salinity (how salty the water is)
Swelling of clays	smectite (a clay mineral that swells) takes in water between the layers of its crystal lattice and grows in volume	contact with fresh or incompatible water
Salt deposits (scale)	calcium carbonate and the sulfates of barium, strontium and calcium come out of the water and settle in the pores	a fall in pressure and temperature, mixing of incompatible waters
Asphaltene, resin and paraffin deposits (ARPD)	paraffin (wax) comes out of the oil when it cools; asphaltenes (the heaviest, sticky part of the oil) come out when the pressure falls or when the oil meets acid	production, injection of cold fluids, acid treatments
Polymers and gel residues	large molecules settle on the pore walls and narrow the channels	drilling fluids and fracturing fluids that contain polymers
Compacted zone around the perforation tunnels	the jet of the shaped charge (an explosive charge that shoots a fast jet of metal) has crushed and compacted the rock, and there is debris in the tunnel	perforating, especially with overbalance

Blocks: phase permeability falls

Mechanism: Water block
What happens: the filtrate (the liquid that leaks out of the mud into the rock) raises the water saturation (the share of the pore space filled with water) near the wellbore, and the relative permeability to oil or gas (the share of the rock's permeability that is open to them) falls
Especially dangerous: low-permeability and gas reservoirs, where high capillary pressure (the pull that tiny pores exert on water) holds the water in place for months

Mechanism: Emulsion block
What happens: filtrate, oil, surfactants (surface-active agents) and fine particles form a thick emulsion (a mixture of tiny droplets of one liquid in another) in the pores
Especially dangerous: oil-based muds, acid treatments

Mechanism: Change of wettability
What happens: surfactants from the mud make the surface of the grains hydrophobic (water-repelling), and the oil flows worse
Especially dangerous: muds with surfactants and oil-based muds

Mechanism: A third phase in a gas reservoir
What happens: hydrocarbon filtrate takes up part of the pores and hinders the flow of gas
Especially dangerous: gas reservoirs, oil-based muds

Mechanism	What happens	Especially dangerous
Water block	the filtrate (the liquid that leaks out of the mud into the rock) raises the water saturation (the share of the pore space filled with water) near the wellbore, and the relative permeability to oil or gas (the share of the rock's permeability that is open to them) falls	low-permeability and gas reservoirs, where high capillary pressure (the pull that tiny pores exert on water) holds the water in place for months
Emulsion block	filtrate, oil, surfactants (surface-active agents) and fine particles form a thick emulsion (a mixture of tiny droplets of one liquid in another) in the pores	oil-based muds, acid treatments
Change of wettability	surfactants from the mud make the surface of the grains hydrophobic (water-repelling), and the oil flows worse	muds with surfactants and oil-based muds
A third phase in a gas reservoir	hydrocarbon filtrate takes up part of the pores and hinders the flow of gas	gas reservoirs, oil-based muds

Gas coming out of solution near the wellbore at a pressure below the bubble point pressure (the pressure at which gas starts to come out of the oil) has a similar effect. So does condensate dropping out near gas-condensate wells (wells whose gas leaves liquid droplets as the pressure falls). Both are counted as an operational component of skin: they depend on how the well is run, not on damage to the rock.

How the phases share the pore space is explained in the lessons on relative permeability and wettability. The difference between the two groups matters for damage. We clear plugging by dissolving the particles or by bypassing the damaged zone. We clear a block by getting the water out, breaking the emulsion or restoring the wettability. A water block sometimes goes away by itself, but in tight rock (rock with very low permeability) it takes months.

Damage also increases the inertial pressure losses (the extra losses that appear at high velocity, when the fluid speeds up and slows down in the twisting pore channels). Flow velocities are highest near the wellbore, and in a zone of lower permeability the resistance to inertial flow is even greater. So in gas wells and high-rate wells, damage also increases the part of the skin that grows with the rate (more detail in the advanced section).

Damage skin: the model of a zone of reduced permeability

To express damage as a number, we replace the real picture with a simple model. Around the wellbore of radius $r_w$ lies a ring of radius $r_d$ with a uniform, reduced permeability $k_d$ . Beyond it is the undamaged reservoir with permeability $k$ . Steady flow (flow in which the pressures no longer change with time) through the ring gives an extra pressure drop, and the skin expresses exactly this drop (the derivation is in the lesson on the skin factor).

Skin of a zone of reduced permeability (Hawkins formula)

S_d = \left(\frac{k}{k_d} - 1\right)\ln\frac{r_d}{r_w}

where:

$S_d$ damage skin, —
$k$ permeability of the undamaged reservoir, mD
$k_d$ permeability of the damaged zone, mD
$r_d$ radius of the damaged zone from the well axis: the well radius plus the depth of damage, m
$r_w$ well radius, m

Units: any consistent units: only the ratios $k/k_d$ and $r_d/r_w$ enter the formula; the logarithm is natural (base e)

Holds when

The damaged zone is a cylinder of uniform permeability, small compared with the drainage area (the part of the reservoir that feeds the well).
The flow is radial over the whole thickness: open hole, or perforations that do not reach beyond the zone (then the actual skin is even larger, because the flow converges on the tunnels).
Single-phase flow that follows Darcy's law (the rate is proportional to the pressure gradient).

A ring in which the permeability is lower by a factor of $k/k_d$ works as an extra resistance in series, one that the flow must pass in addition to the rest of the reservoir. The degree of permeability reduction enters the skin linearly (in direct proportion). The radius of the zone enters through a logarithm. The extra pressure drop $\Delta p_d = qB\mu S_d/(2\pi kh)$ grows with the rate.

CalculatedThe share of the rate that a damaged well keeps, against the remaining permeability of the zone

k_d/k

, for three depths of damage (measured from the borehole wall). The well radius is 0.108 m, the drainage radius is 300 m, and there are no other components of skin. A and B are the drilling fluids of the example below.

In reality the permeability changes with the distance from the wellbore. At the wall there is an internal cake of mud particles with very low permeability. Further out is the invaded zone (the part of the rock that the filtrate has entered), where the permeability is reduced only moderately. Further still is the undamaged reservoir. The rings work in series, so their extra resistances add up:

Damage skin for several concentric zones

S_d = \sum_{i=1}^{n} \left(\frac{k}{k_i} - 1\right)\ln\frac{r_i}{r_{i-1}},\qquad r_0 = r_w

where:

$k_i$ permeability of the $i$ -th ring, mD
$r_{i-1},\ r_i$ inner and outer radii of the $i$ -th ring, measured from the well axis, m
$k,\ r_w$ permeability of the reservoir and well radius, mD, m

Units: any consistent units

Holds when

The same as for one zone. Inside each ring the permeability is uniform.

A thin ring of very low permeability can contribute more than a thick ring of moderate permeability. The equivalent permeability of the damaged zone is the harmonic mean (an average in which the lowest values count most) with weights $\ln(r_i/r_{i-1})$ , not the arithmetic mean over the thicknesses.

Worked exampleSkin of two-zone damage

Given (assumed data)

Reservoir permeability $k$: 150 mD
Well radius $r_w$ (215.9 mm bit) and drainage radius $r_e$: 0.108 m and 300 m
Zone 1: internal cake at the wall: the first 2 cm, $k_1 = 3$ mD
Zone 2: filtrate invasion: from 2 to 40 cm beyond the wall, $k_2 = 60$ mD

Solution

Radii of the zones from the axis: $r_1 = 0.108 + 0.02 = 0.128$ m, $r_2 = 0.108 + 0.40 = 0.508$ m.
Zone 1: $S_1 = \left(\dfrac{150}{3} - 1\right)\ln\dfrac{0.128}{0.108} = 49\cdot 0.1699 = 8.33$ .
Zone 2: $S_2 = \left(\dfrac{150}{60} - 1\right)\ln\dfrac{0.508}{0.128} = 1.5\cdot 1.3785 = 2.07$ . In total $S_d = 10.4$ . The 2 cm cake accounts for 80% of the skin.
The share of the rate that is kept: $X = \ln\dfrac{300}{0.108} - 0.75 = 7.179$ ; $\dfrac{q_d}{q_0} = \dfrac{7.179}{7.179 + 10.4} = 0.41$ .
The averaging error: the permeability of the zone averaged over the thickness, $(0.02\cdot 3 + 0.38\cdot 60)/0.40 = 57.1$ mD, would give a skin of only 2.5. The correct equivalent permeability, which gives the same skin, is 19.4 mD.
If we remove only the cake (for example, by washing, or with an acid bath, in which acid is left to stand against the wall), $S_d = 2.07$ remains, and the share of the rate rises to 0.78. That is a gain of 1.9 times.

Answer: The damage skin is about 10.4. The well gives 41% of the possible rate. Removing the 2 cm cake almost doubles the rate.

What it means. The thinnest layer decides almost the whole skin. So an average over the thickness is misleading. Cleaning the wall may give more than a deep treatment. Ways to clean the wall are washing, flowing the well back with a large drawdown, and an acid bath. We know the real profile only roughly. We estimate it from tests on core (rock samples taken from the well) and from the volume of filtrate, and we check the result with a well test. The data in this example are assumed for illustration.

Damage and completion: open hole or perforation

With an open hole completion (the reservoir section is left without casing), fluid enters the well through the whole wall, and so through the whole damaged zone. In a cased well it enters only through the perforation tunnels. Suppose the tunnels pass right through the damaged zone and end in undamaged rock. Then most of the flow bypasses the damage, and its effect falls sharply. What remains is the skin of the perforation itself, which depends on the density, length and phasing (the angle between neighbouring shots) of the tunnels (Shaped-charge perforating). Suppose instead that the tunnels end inside the damaged zone. Then the flow converges on them through poor rock, and the damage acts as strongly as in open hole, or even more strongly.

SchematicTop view of a cased and cemented well with six perforation tunnels. On the left the damage is deeper than the tunnels, so all the flow passes through damaged rock. On the right the tunnels reach beyond a thin damaged zone and connect the wellbore with undamaged rock. The diagram is not to scale.

This leads to a conclusion that is not obvious. It concerns the choice of the drilling fluid for the first drilling through the reservoir. A fluid that builds a thin, dense cake gives shallow but severe damage: particles and filtrate hardly go deeper, but the pores right at the wall are blocked. A fluid with a thicker and more permeable cake gives damage that is moderate but deep. For a perforated well the first is better, because the tunnels pass through it. In open hole something else decides: whether we can remove the cake and the blocked layer at the wall when we bring the well on stream. If we can, the first fluid wins again. If we cannot, moderate and deep damage does less harm.

Worked exampleWhich drilling fluid to choose for opening the reservoir

Given (assumed data)

Reservoir: $k = 150$ mD, $h = 12$ m, oil with $\mu = 1.8$ mPa·s, $B = 1.20$ m³/m³
Well: $r_w = 0.108$ m, $r_e = 300$ m, drawdown 3.0 MPa
Fluid A: thin, dense cake: permeability reduced to 6 mD to a depth of 0.10 m
Fluid B: thick, permeable cake: permeability reduced to 60 mD to a depth of 0.90 m
Perforation (if the well is cased): tunnels go 0.30 m into the rock

Solution

Skin of fluid A: $S_A = \left(\dfrac{150}{6} - 1\right)\ln\dfrac{0.208}{0.108} = 24\cdot 0.6554 = 15.7$ .
Skin of fluid B: $S_B = \left(\dfrac{150}{60} - 1\right)\ln\dfrac{1.008}{0.108} = 1.5\cdot 2.2336 = 3.35$ .
The rate of the undamaged well (oil at surface conditions): $q_0 = \dfrac{0.536\cdot 150\cdot 12\cdot 3.0}{1.8\cdot 1.20\cdot 7.179} = 187$ m³/d. Open hole: with fluid A, $q = 187\cdot\dfrac{7.179}{7.179 + 15.7} = 58$ m³/d; with fluid B, 127 m³/d.
Cased hole: tunnels 0.30 m long pass right through the damage of fluid A (0.10 m), and the rate approaches 187 m³/d, less the skin of the perforation itself. The tunnels do not pass through the damage of fluid B (0.90 m). The flow converges on them through damaged rock, and the rate will be about 127 m³/d, or lower if the tunnels are short and few.
The cost of a wrong choice for open hole: $127 - 58 = 69$ m³/d (432 bbl/d, with 1 m³ = 6.29 barrels). At the assumed price of US$50 per barrel, taken from the example project that runs through the economics lessons (Project cash flow), this is about US$22 thousand of revenue per day.

Answer: For an open hole, fluid B is better (

S

≈ 3.35 against 15.7). For a cased and perforated well, fluid A is better, because the perforation bypasses its shallow damage.

What it means. The same fluid can be the best for one kind of completion and the worst for another. So we choose the fluid for opening the reservoir together with the design of the well bottom. The conclusion for a cased well depends on the tunnels really being longer than the damaged zone. The margin here is 0.20 m, and uncertainty in the depth of the damage and in the length of the tunnels in the reservoir can use it up. The data in this example are assumed for illustration.

How to recognise damage

Damage does not show on well logs and cannot be measured directly. We judge it by how the well behaves and from indirect data. Each sign can also have other explanations, so we compare the signs with each other.

Signs of damage

Sign: Productivity (the rate per unit of drawdown) below what we expect from $kh$ taken from core, logs or neighbouring wells
What it suggests: possible damage
Other possible causes: an error in $kh$ , partial penetration, a limit set by the lift system (the tubing that carries the fluid up the well), low reservoir pressure

Sign: A large skin from a well test after the pseudo-skins have been subtracted
What it suggests: damage of the near-wellbore zone
Other possible causes: an unaccounted geometry of the opening, inertial losses (the skin grows with the rate)

Sign: An interval that looks good on logs hardly works on the inflow profile (a log that shows how much each interval produces)
What it suggests: damage of this interval
Other possible causes: depletion of the interval, perforations that do not work, flow behind the casing

Sign: A sudden fall in productivity after an operation
What it suggests: damage caused by well killing, a workover or a treatment
Other possible causes: coincidence with water breakthrough or a pressure drop

Sign: A gradual fall in productivity or injectivity (the rate an injection well takes per unit of pressure)
What it suggests: deposits of salts and ARPD, fine particles carried out of the rock, clogging of an injection well
Other possible causes: depletion of the reservoir, a rising water cut (the share of water in the produced fluid)

Sign	What it suggests	Other possible causes
Productivity (the rate per unit of drawdown) below what we expect from $kh$ taken from core, logs or neighbouring wells	possible damage	an error in $kh$ , partial penetration, a limit set by the lift system (the tubing that carries the fluid up the well), low reservoir pressure
A large skin from a well test after the pseudo-skins have been subtracted	damage of the near-wellbore zone	an unaccounted geometry of the opening, inertial losses (the skin grows with the rate)
An interval that looks good on logs hardly works on the inflow profile (a log that shows how much each interval produces)	damage of this interval	depletion of the interval, perforations that do not work, flow behind the casing
A sudden fall in productivity after an operation	damage caused by well killing, a workover or a treatment	coincidence with water breakthrough or a pressure drop
A gradual fall in productivity or injectivity (the rate an injection well takes per unit of pressure)	deposits of salts and ARPD, fine particles carried out of the rock, clogging of an injection well	depletion of the reservoir, a rising water cut (the share of water in the produced fluid)

What we need to know depends on the choice we make. To bypass the damage with hydraulic fracturing, it is enough to know that the damage exists: a fracture will pass through any near-wellbore zone. To remove it with a treatment, we need to know the type of damage and where it is. Acid, solvent and surfactants (surface-active agents) each act on their own kind of damage, and a wrongly chosen mixture will either not help or do harm. So we study the history of operations on the well: which fluids were pumped into it, and when. We analyse the deposits and the particles carried out of the well. We run tests on core with these fluids. And we examine the damaged rock under an electron microscope.

Prevent, remove or bypass

Prevent: Keep the overbalance small when the reservoir is opened, and where possible drill and perforate underbalanced (with the well pressure below the reservoir pressure). Use drilling fluids for the first opening that contain bridging agents (particles that quickly seal the pore openings at the wall) of a chosen size, soluble in acid or water (calcium carbonate, salt). Use a filtrate that is compatible with the clays and the formation water (for example, potassium chloride solutions). Use filtered kill fluids and clean tanks and pipes. Bring the well smoothly up to its operating regime. Use scale inhibitors (chemicals that stop mineral deposits from forming). This is always cheaper than curing damage.
Remove: Acid treatments: hydrochloric acid in carbonates, and mixtures with hydrofluoric acid in sandstones (Acid treatments: principle, economics and candidate selection). Solvents for ARPD. Surfactants and mutual solvents (liquids that dissolve in both oil and water) against water and emulsion blocks. Mechanical cleaning. We need to know the type and the place of the damage.
Bypass: Perforate deeper than the damaged zone, re-perforate with more powerful charges, or use hydraulic fracturing (Hydraulic fracturing: purpose and well selection). It is enough to know that damage exists. Hydraulic fracturing also gives a negative skin (a skin below zero: the zone around the well helps the flow).

The size of the bridging particles is chosen from the size of the pore throats. A widely used rule of thumb is this. Particles that are at least one third of the throat diameter, at a high enough concentration, stop at the wall and form an external cake (a layer on the wall surface), which is easy to remove later. Particles from one tenth to one third of the diameter go deeper and plug the pores from inside. Smaller ones pass right through. A drilling fluid for opening the reservoir needs a mixture of particles that quickly builds a thin external cake and keeps the fine particles out (Drilling fluids: functions and properties).

How we decide what to do with a damaged well

1
Isolate the damage skin
From the skin of the well test we subtract the pseudo-skins of partial penetration, perforation and well inclination. We find the skin that grows with the rate by testing at several rates.
2
Check what limits the rate
If the lift system limits the rate, reducing the skin will give little (Nodal analysis of the production system).
3
Find the type and place of the damage
Use the history of operations, the deposits and the particles carried out, and core tests.
4
Compare the options
We weigh the extra production from a treatment, hydraulic fracturing or re-perforation against the cost and the risk.
5
Change the technology
We remove the cause of the damage on the next wells and at the next workovers.

Terms and symbols

Formation damage (contamination of the near-wellbore zone): A reduction in the permeability of the near-wellbore zone, compared with the original value, caused by operations on the well or by its production.
Damage skin $S_d$: The component of the skin factor caused by a reduction in the permeability of the near-wellbore zone. It is the only one that a treatment can remove or bypass.
Pore plugging (bridging): Blocking of pores by particles of drilling fluid or cuttings. Bridging agents are particles chosen on purpose to form a filter cake quickly.
Water block: A drop in the phase permeability to oil or gas because the water saturation near the wellbore is raised after filtrate has invaded.
Fines migration: Fine particles are torn loose and carried by the flow, and then plug the pore channels.
ARPD: Asphaltene, resin and paraffin deposits: paraffins, resins and asphaltenes that come out of the oil when it cools and when the pressure falls.
Return permeability: The ratio of the permeability of a core sample after exposure to a fluid to its original permeability. It is used to compare fluids.

Common mistakes and misconceptions

Wrong

“A well test gives a skin of +12, so the reservoir is badly damaged.”

In fact

First we subtract the pseudo-skins of partial penetration, perforation and well inclination, and we separate the skin that grows with the rate. The damage skin that is left may be much smaller.

Wrong

“Only a couple of centimetres at the wall are damaged, so it is nothing to worry about.”

In fact

A thin layer of very low permeability can give a skin of 8–10 or more and take away half of the rate. The depth enters the skin through a logarithm, and the degree of permeability reduction enters linearly.

Wrong

“A cased well always needs the drilling fluid that causes the least damage.”

In fact

If the perforation tunnels pass right through the damaged zone, the depth of the zone matters most. Perforation bypasses shallow, severe damage, but deep, moderate damage stays.

Wrong

“Acid will cure any damage.”

In fact

Acid does not dissolve barium sulfate, for example, and it does not remove a water block. A wrongly chosen acid can cause secondary precipitates (new deposits formed by the reaction products), emulsions and asphaltenes coming out of the oil. First we establish the type of damage.

Wrong

“Damage happens only during drilling.”

In fact

Cementing, perforating, killing the well with unfiltered fluids, fine particles that the flow carries along, deposits of salts and ARPD during production, and injection of dirty water all damage the reservoir too.

In depth: advanced detail

A continuous damage profile

If the permeability changes smoothly with the distance from the wellbore, the rings become infinitely thin and the sum turns into an integral:

Damage skin for a continuous permeability profile

S_d = \int_{r_w}^{r_d} \left(\frac{k}{k(r)} - 1\right)\frac{\dd r}{r}

where:

$k(r)$ permeability at the distance $r$ from the well axis, mD
$r_d$ the radius beyond which the permeability equals the reservoir permeability, m
$k,\ r_w$ permeability of the reservoir and well radius, mD, m

Units: any consistent units

Holds when

Radial steady-state flow in the near-wellbore zone, and single-phase flow that follows Darcy's law.

The contribution of each thin ring is proportional to $\dd r/r$ , so the rings at the wall itself “weigh” the most. For example, suppose the permeability grows linearly with $\ln r$ , from $k_w$ at the wall to $k$ at the radius $r_d$ . Then the integral gives $S_d = \ln\dfrac{r_d}{r_w}\left[\dfrac{\ln(k/k_w)}{1 - k_w/k} - 1\right]$ .

With $k_w/k = 0.04$ and $r_d/r_w = 3$ we get $S_d = \ln 3\,(\ln 25/0.96 - 1) \approx 2.6$ . A uniform zone of the same radius, with the permeability that the wall has, would give $24\ln 3 \approx 26$ . A gradual recovery of permeability makes the damage ten times milder. So it matters how fast the permeability recovers with distance from the wall, and not only what its value is at the wall.

Damage and inertial losses

At high velocities an inertial resistance is added to the viscous one. The Forchheimer equation describes it (Rock permeability). For radial flow, its contribution to the pressure drop between $r_w$ and $r$ comes from integrating $\beta\rho v^2$ with the velocity $v = q/(2\pi r h)$ :

Inertial addition to the pressure drop in the near-wellbore zone

\Delta p_{\text{inert}} = \frac{\beta\,\rho\,q^2}{4\pi^2 h^2}\left(\frac{1}{r_w} - \frac{1}{r}\right)

where:

$\beta$ inertial resistance coefficient of the rock, m⁻¹
$\rho$ fluid density at reservoir conditions, kg/m³
$q$ flow rate at reservoir conditions, m³/s
$h$ reservoir thickness, m
$r_w,\ r$ well radius and distance from its axis, m

Units: SI

Holds when

A zone with a uniform $\beta$ and radial flow over the whole thickness. In the damaged zone, we use its own coefficient $\beta_d$ instead of $\beta$ .

The factor $1/r_w - 1/r$ is built up mostly in the first few tens of centimetres. The inertial losses are concentrated right at the wellbore, which is where the damage lies. The coefficient $\beta$ grows as the permeability falls (in different correlations, as $k$ raised to a power between −0.5 and −1.5). So when the permeability near the wellbore is reduced 10 times, the inertial losses in this zone grow several times, or even tens of times. In a perforated well the flow also converges on the tunnels, and the velocities at their walls are higher still.

Connections to other topics

Skin factor — the skin factor, the Hawkins formula, flow efficiency and the components of skin.
Sources of formation damage — sources of damage during drilling, cementing, perforating, production and workovers.
Borehole environment: invaded zone and mudcake — the zone invaded by filtrate and the mudcake as the logs see them.
Acid treatments: principle, economics and candidate selection — how acid removes damage and how wells are chosen for treatment.
Hydraulic fracturing: purpose and well selection — how a fracture bypasses the damaged zone.
Shaped-charge perforating — the length and density of perforation tunnels, and the perforation skin.
Drilling fluids: functions and properties — drilling fluids for opening the reservoir, and control of filtration (the loss of fluid into the rock).
Nodal analysis of the production system — when a lower skin really does increase the rate.

Check yourself

1
Which of these mechanisms reduces not the absolute permeability of the rock but the phase permeability to oil or gas?
1. A.Swelling of smectite
2. B.Deposition of barium sulfate
3. C.Water block
4. D.Plugging of channels by particles of weighting material
Show the answer
Correct answer: C. Water block
In a water block the pore channels stay open, but the raised water saturation near the wellbore lowers the relative permeability to oil or gas. The other mechanisms physically narrow or close the channels.
2
The reservoir permeability is 100 mD. Around a wellbore of radius 0.1 m it is reduced to 20 mD in a zone of radius 0.4 m from the axis. Find the damage skin and the share of the rate that is kept, if $X = \ln(r_e/r_w) - 3/4 = 7$ .
Show the answer
$S_d = (100/20 - 1)\ln(0.4/0.1) = 4\ln 4 \approx 5.5$ . The share of the rate is $7/(7 + 5.5) \approx 0.56$ : the well loses almost half of its possible rate.
3
A well will be cased and perforated, with tunnels 0.35 m long in the rock. Fluid A gives severe damage to a depth of 0.08 m. Fluid B gives moderate damage to 0.7 m. Which should we choose?
1. A.Fluid B: its damage is milder
2. B.Fluid A: the tunnels will pass right through its damage
3. C.It makes no difference: perforation bypasses any damage
4. D.We cannot choose without the reservoir permeability
Show the answer
Correct answer: B. Fluid A: the tunnels will pass right through its damage
Tunnels 0.35 m long reach beyond the shallow damage of fluid A and connect the wellbore with undamaged rock. The damage of fluid B is deeper than the tunnels, and the flow to them goes through damaged rock. For an open hole the choice could be the opposite.
4
What reduces the productivity of a well of radius 0.1 m more: a 100-fold reduction in permeability in a layer 1 cm thick, or a 2-fold reduction in a zone 1 m thick?
Show the answer
The thin layer: $S = 99\ln(0.11/0.1) \approx 9.4$ . The thick zone: $S = 1\cdot\ln(1.1/0.1) \approx 2.4$ . The skin of the thin but badly damaged layer is almost four times larger, and it lowers productivity much more.
5
After water breakthrough, the productivity of a production well began to fall gradually, although the reservoir pressure is maintained. Which damage mechanism is the most likely?
1. A.A compacted zone around the perforation tunnels
2. B.Swelling of clays by drilling fluid
3. C.Invasion by filtrate of the cement slurry
4. D.Fines migration and salt deposition
Show the answer
Correct answer: D. Fines migration and salt deposition
Moving water, the wetting phase, tears loose and carries fine particles. Mixing of incompatible waters and falling pressure cause salts to deposit. Both processes develop gradually during production. The other options are damage from the construction of the well, and they would have shown up at once.
6
Why is it enough to know that damage exists for hydraulic fracturing, while an acid treatment needs to know its type and place?
Show the answer
A fracture goes far beyond the near-wellbore zone and bypasses damage of any kind. Acid, a solvent or a surfactant acts only on its own kind of damage, and it must reach the place where that damage is. A wrongly chosen mixture will not help, and it may even create new damage.

Updated: 19 October 2026