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 (cations). Cations 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) Emulsions
3. Increase in Free Water Content from Change in Wettability:
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 (Pwellbore > Preservoir): 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 (Pwellbore < Preservoir): 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).