The formation skin can be caused by plugging of the pore space by solid particles, by mechanical crushing or disintegration of the pore medium, or by fluid effects, such as the creation of emulsions or changes in relative permeability.
Pore plugging by solid particles is the most aggressive of the mechanisms and can come from several sources, including injection of solids into the formation, dispersion of clays into the rock matrix, precipitation, and bacterial growth.
The main sources of formation skin in wells are listed below:
Sources of Formation Skin
During Drilling
The most common source of Formation Skin in wells is during the drilling process. Well damage results from encroaching particle formation and drilling fluid filtrate.
The skin caused by drilling mud particles is considered one of the most severe.
The deposition of drilling mud particles around the hole can severely reduce permeability in this critical region. Fortunately, however, the depth of particle invasion is generally small, ranging as small as 1 inch and as deep as 1 foot.
To minimize this skin, the drilling mud particles must be larger than the formation pores, suggesting that the mud should be 5% vol. of mud particles with a diameter greater than 1/3 of the pore size, to prevent significant mud invasion into the formation.
Even if the invasion of mud particles within the formation is small, the formation skin is frequently reversible, performing special perforating and/or stimulations.
Drilling mud filtrate can invade the formation much deeper than mud particles, with invasion depths ranging from 1 – 6 feet.
As filtrate enters the formation, drilling mud cake begins to form on the face of the sand, which helps decrease mud filtrate.
However, the mud cake begins to be eroded by the shear stresses of the drilling mud.
The dynamic filter rate for this balance between the mud cake and erosion is given by the following expression:
Where
- uf is the flow rate of the mud filtrate in cm/hr
- C is the dynamic coefficient of fluid loss of the mud cake in cm3/cm2-hr1/2
- t is the exposure time in hr
- b is a constant that quantifies the stability of the mud cake
- y' is the shear rate in seconds-1
Studies in this field have shown that the values of b are between 2×10-8 and 5×10-7 cm3/cm2. The fluid loss coefficient can be obtained in the laboratory with a dynamic fluid loss test.
The drilling of horizontal wells have reported horizontal sections of up to 8,000 feet, which expose new problems with significant penetration, which translates into skin due to exposure times of the drilling mud when the horizontal section is drilled.
The shape of the skin along the horizontal section is probably a reflection of the long exposure near the vertical section of the hole.
During Completion
Formation skin during the well completion can be caused by the invasion of completion fluids within the formation, by cementing and perforating, or by the application of different stimulation techniques.
The primary purpose of completion fluid is to contain the high bottomhole pressure relative to reservoir pressure (overbalancing), completion fluids are forced into the formation.
Thus, if the completion fluids contain solids or chemicals that may be incompatible with the formation, the skin caused may be similar to the skin caused by drilling mud.
It is very important that completion fluids are well filtered to prevent injection of solids into the formation.
It is recommended that completion fluids contain no more than 2 ppm solids less than 2 microns in size.
Cement filtrates are other potential fluids that can cause serious damage when they enter the formation.
Cement filtrates generally contain a high concentration of calcium ions, so precipitation damage can occur.
However, the small volume of cement filtrate limits this skin to an area very close to the well.
Perforating is an inevitable consequence of formation crushing in the near wellbore.
This damage is minimized by perforating underbalanced, that is, when the hydrostatic pressure is lower than the formation pressure.
Reglas generales sobre el bajo balance requerido en zonas de gas y petróleo se pueden observar en las Figura 1 y Figura 2.
The minimum overbalancing required for a given formation permeability can be read from the correlation trend plotted in the figures.
An alternative to perforating underbalanced to obtain clean bore tunnels is to perforate with extreme overbalance.
In this technique, the pressure in the wellbore is above the fracture pressure at the time the perforations are created, with a pressure gradient generally above 1.0 psi/ft.
Additionally, the bottomhole pressure and tubing are partially filled with gas, so that the high pressure is maintained for a short duration after the perforations are created.
The well configuration for end-overbalanced perforating is shown in Figure 3.
This technique is designed to create a network of small fractures that extend from the hole created, as seen in Figure 4, providing a place for the debris originated from the perforation to move away from the tunnels of the perforated ones.
Stimulation fluids, designed to increase well productivity, can themselves cause formation skin through solids invasion or precipitate formation.
Originated by Production
Formation skin during the productive life of the well can be caused by fines migration or by precipitates.
The high velocity in the porous media close to the face of the sand can sometimes be enough to mobilize the fines that can cause plugging of the pore throats.
Several studies have shown that there is a critical speed, above which formation skin by migration of fines begins to occur.
Unfortunately, this critical velocity is particularly dependent on the type of rock and complex shaped fluid, so the only way to determine this critical velocity is through core flood analysis.
Fines can be moved to the near wellbore when water production begins.
Figure 5, this mechanism can be shown. Fines are most likely to be moved when the phases that wet them are mobile, and since most formations are water-wet, the presence of mobile water can cause fines migration and subsequent formation skin.
Solids precipitation, either inorganic material from connate water or organic solids from petroleum, can occur close to the producing well, due to pressure reduction close to the sand face.
These sources of formation skin can often be removed with stimulation treatments (acid stimulations to remove carbonate precipitates or solvents for wax removal).
Originated by Production
Injection wells are susceptible to the formation of damage by the injection of solid particles, by precipitation due to incompatibility of the injected water and the formation water, or by bacterial growth.
The injected solids are always harmful, if the injection water is not passed through a filtration process. Filtration must remove all particles larger than 2 microns.
Solids precipitation damage can occur whenever injection water is mixed with formation water leading to supersaturation.
The most common problem is the injection of water with a high concentration of sulfate or carbonate ions into the formation with divalent cations, such as calcium, magnesium, or barium.
Due to cation exchange with formation clays, they can release divalent cations into the solution when water of different ionic composition is injected.
Precipitation can occur in the formation even when the injection water is apparently compatible with the formation water.
The fact that precipitation will not occur when a formation water sample is mixed with an injection water sample is not a sufficient guarantee that precipitation will not occur within the formation.
Cation exchange should be considered as a dynamic process.
Injection water may contain bacteria, which can plug the formation like any other solid particle.
The injected bacteria can also grow in the near wellbore, causing severe formation skin. The water injection should be examined for the presence of bacteria.
If they are present, they must be added bactericide to the injection water.
Figures taken from the book Petroleum Production Systems by Michael J. Economides et al.