Formation Damage:
Improving well performance
Minimizing the formation damage has a great impact on improving
well performance.
Any phenomenon that causes a distortion of the flow lines from
the perfectly normal to the flow direction or a restriction to flow
would result in positive skin effect.
Positive skin can be created by Mechanical causes (partial
completion, inadequate number of perforations), Phase changes
(reduction of relative permeability of the desired fluid),
Turbulence and damage to the natural reservoir permeability.
Negative skin denotes that the pressure drop in the
near-wellbore zone is less than would have been from the normal
undisturbed reservoir flow mechanisms.
Causes of negative skin:
Matrix stimulation
Hydraulic fracture
Highly inclined wellbore
Formation Damage:
Formation damage refers to the decrease in permeability that can
occur in the near wellbore region of a reservoir. This represents a
positive skin effect. The three main sources of formation damage
are:
A rule of thumb is that one half of the pressure drop between
the drainage pressure and the wellbore (the drawdown pressure)
should occur no less than 15 feet of the wellbore.
Drilling Fluid: Drilling fluid (mud) is used during drilling to
remove cuttings from the well. The fluid is pressurized in the well
to help prevent formation fluids (gas, oil, water) from escaping
during the drilling. It is typically a mixture of clay and water
with chemical additives which are used to control fluid properties
such as viscosity. The drilling fluid flows through the well and
back to the surface where cuttings are removed in gravitational
settlers. The fluid is then recirculated back to the well. As a
result, the drilling fluid has a very high solids content. Because
it is pressurized, the drilling fluid filtrate (fluid and fine
particles) can flow radially into the formation (typically up to
6'). A filter cake or mud cake forms typically within the first
twelve inches of the wellbore radius.
Causes of Formation Damage:
The main causes of formation damage are:
Pore Obstruction: Pores within reservoir rock represent pathways
which vary greatly in shape and orientation. The basic model of a
pore is:
The throat of the pore causes the most significant restriction
to the flow of fluid and is therefore an important determinant of
the permeability. Fine particles can be transported within the
network of pores. If the particles deposit near the throat of the
pore, they will significantly restrict the flow. In some cases
particles can bridge the opening at the throat, blocking the
flow.
The finest particles in the vicinity of the pores are clay
particles, which typically have diameters less than 10 (m. Clay
particles have negatively charged surfaces (anions) and adsorb
positively charged species (cat ions). Cat ions can have one or
more positive charges, for example: monovalent (K+, Na+), divalent
(Ca2+, Mg2+, Ba2+). Clay particles can be found in external fluid
mixtures which enter the formation during completion and
stimulation including drilling filtrate.
Clay particles are also naturally dispersed on the pore surface
of the reservoir rock. A change in the salt concentration
(salinity) or pH of the reservoir fluid can liberate these clay
particles. A change in salinity can also cause the clay particle to
swell. The degree to which salinity affects the permeability is
known as "water sensitivity".
Clay particle dispersion (release and entrainment) can be
limited by controlling the composition of the external fluids:
Desired:
What we need to do:
Chemical Precipitation:
Chemical precipitation causes the formation of fine solid
particles. The particles can act to restrict or block the flow of
fluid through the pores of the reservoir rock. Precipitation will
occur when the reservoir fluid comes in contact with foreign fluids
or through changes in temperature and pressure. The precipitates
can be inorganic (ex. CaCO3) or organic (ex. waxes or
asphaltenes).
Fluid Damage:
Fluid damage refers to the reduction in permeability that occurs
with a change in the character of the fluid as opposed to a change
in the reservoir rock. Reduction in permeability through fluid
damage can occur through three main mechanisms:
1. Increase in Water Content From Foreign Fluid:
2. Formation of Water in Oil (W/O) Emulsions3. Increase in Free
Water Content from Change in Wet ability: It is important to test
the drilling mud, cementing fluids and stimulation fluids for
compatibility with reservoir fluids and rock to reduce the risk of
chemical precipitation and fluid damage. In addition, the effects
of temperature and pressure on the reservoir fluids must be tested
to determine the level of precipitation that will occur. This
information is used to define the optimum operating conditions.
Mechanical Damage: Mechanical damage results from physical
compaction or pulverizing of rock. The collapse of a weak formation
is considered mechanical damage but the damage associated with
perforation represents the most significant cause. Even though
perforation damage is associated with a small region near the
wellbore, it can cause a significant restriction to flow.
Perforation: Perforation creates a flow path for fluids from the
reservoir through the cement and casing to the wellbore. There are
four main methods of perforation:
Jet Perforation Equipment: The gun is inserted into the well
either through a hollow steel carrier (for a larger casing gun) or
through production tubing (through-tubing gun). The guns are either
detonated through an electrical cable originating at the surface or
by a detonator attached to the bottom of the gun that is initiated
on impact with the bottom of the well. Tunnels which are 0.25 to
0.40" in diameter and 6 to 12" in length are typically created by
jet perforation guns.
The performance of the jet perforation guns is affected by:
Controlling the pressure in the reservoir
1) Overbalanced Perforating (Wellbore > Reservoir): Here the
primary concern is the selection of clean (and in some cases
acidic) fluid in the wellbore to ensure minimal perforation
plugging. The higher wellbore pressure ensures that no reservoir
fluid flows to the well.2) Underbalanced Perforating (Wellbore <
Reservoir): This method is not as safe as overbalanced perforating
since reservoir fluid can flow to the well and cause blowout.
Differential pressures are maintained at a low value (200 to 400
psi) to reduce the fluid flow from the reservoir. The advantage of
underbalanced perforating is that the amount of shrapnel and other
materials entering the reservoir is minimized.
The additional resistance associated with perforation may be
treated as a separate skin factor rather than part of the skin
factor associated with formation damage.
Components of the Skin Effect:
Previously, all of the aspects associated Skin Effect and
non-Darcy flow were lumped together using two coefficients, S and
D. It is often more useful to look at the specific components that
make up the skin effect. The most significant components
include:
In a well with a large skin effect, it is important to determine
the most significant contributors to the restriction before action
is taken.
Consider the following two cases:
Case 1: S = Total Skin = +5: Sd = 0; Sp = +5;
In this case the restriction to flow is due to the perforations
and not to formation damage. The most effective action is to
improve the perforations.
Case 2: S = Total Skin = +5: Sd = +5; Sp = 0;
In this case, the same total skin is observed but the
restriction is the result of formation damage and no contribution
from the perforations. The most effective action is to consider
stimulation.
Perforation Skin:
The perforation skin (Sp) is a function of perforation length
(l), perforation diameter (d), spacing in shots per foot (SPF), and
phasing angle (().
OTHER COMPONENTS OF SKIN:
Formation Damage: One method of representing this term is
through Hawkins formula (as discussed earlier):
Turbulence (Non-Darcy) Skin:
Partial Completion and Slant:
These two skin effects can be determined using the method of
Cinco-Ley et al. (1975) using the dimensionless parameters hD =
h/rw: zw/h; hw/h and ( {degrees} where h is the height of the
reservoir, hw is the height of the perforation interval, zw is the
elevation of the midpoint of the perforations relative to the
formation base, and ( is the slant angle relative to the vertical
axis (more information on p. 88 of Course Text).