Chapter 2
INTRODUCTION
Formations that are considered soft or
poorly consolidated are often plagued
by sand production tendencies.
Formation sand production results in
lost production and plugged gravel
packs, screens, perforations, tubulars,
surface flow lines, and separators. In
addition to damage caused to surface
equipment by plugging, casing and
surface equipment can erode due to
abrasive, sand-laden fluid flow from
the well. Worst-case sand production
problems can cause total well failure or
the need for recompletion from casing
collapse, openhole collapse, or both.
Conventional treatments for sandproducing wells include gravel packing,
sand consolidation, and resin-coated
sand slurries. These treatments minimize
the effect of sanding and are based on
gravel-packing technology, which bridges
the produced fines. This restrictive or
filtrative nature of the gravel pack is
effective for a while, but over time the
permeability of the pack decreases.
Permeability damage to the pack causes
a high, positive skin in the near-wellbore
area, which may cause a tremendous
decrease in well productivity. Figure 2.1
shows the effect that sanding has on a
gravel pack.
Rock
Mechanics
and
Sanding
Tendency
Fracturing high-permeability reservoirs
has now gained wide acceptance as an
effective method by which to control
Productivity
Profile of Well Requiring FracPac Services
Normal
Decline
Apparent Gravel
Pack Failure
FracPac
Treatment
Regravel
Pack
Time
Figure 2.1 — The normal production decline of a well is shown by the red curve.
The production decline of a well treated with a conventional gravel pack is depicted
by the solid black curve. Even after a second application of gravel packing is
performed, the gravel pack plugs with sand and the well’s production declines
quickly. The dashed curve denotes the production decline after a FracPac treatment.
Productivity is drastically improved initially, and the production decline parallels the
normal decline thereafter.
5
FRACPAC COMPLETION SERVICES
sanding and to bypass near-wellbore damage, stimulating
production. From a rock mechanics perspective, this
chapter focuses on the benefits of performing FracPac
Completion Services for stimulation, sand control, or
both. Topics such as drawdown, in-situ stresses, failure
mechanisms, sanding-tendency prediction, tip-screenout
fracturing, and fracture behavior are discussed in detail
and show how FracPac procedures can help overcome
production problems caused by sanding.
DRAWDOWN DUE TO FLUID FLOW
A high production rate from a highly permeable reservoir
causes a high drawdown across the formation in the
vicinity of the wellbore. This drawdown places increased
deviatory stress on the formation, which, if it exceeds the
strength of the formation, can cause formation failure
and resulting sand or fines production.
It is important to understand the pressure-drawdown
components that contribute to the overall pressure drop
that occurs in the proximity of the wellbore. In addition to
the energy loss in Darcian flow, the drawdown must overcome the following flow impairments:
• Radial flow convergence, momentum effects, and
permeability damage from the near-wellbore stress field
induced by drilling
• Wellbore flow impairment, such as partial penetration,
perforation, and skin damage
• Damage farther into the formation caused by drilling
mud and fines invasion (damage from drilling
and production)
The factors listed previously contribute to a large
drawdown within a small area adjacent to the wellbore.
In addition to the pressure disturbance acting on the fluid
in the pores of the formation, a near-wellbore mechanical
stress-concentration zone is created, which will be
discussed in detail later in this chapter. The effective
stress on the formation (the total stress minus the pore
pressure) increases significantly near the wellbore, and
with this, the risk of formation failure rises during the
early stages of production. Formation failure can still
occur at a later time as the reservoir is depleted by
production; however, if the drawdown is eased at the
wellbore, a more stable stress field occurs. Reducing
drawdown is one of the major objectives when
performing FracPac Completion Services.
6
FracPac Completion Services are designed to create short,
wide, and highly conductive fractures that bypass nearwellbore damage, creating a channel from the undamaged
formation to the wellbore. Bypassing the near-wellbore
damage helps to decrease the drawdown at the wellbore
for a given production rate.
Two parameters that control the production increase of a
well that is hydraulically fractured are fracture
conductivity (kf bf ) and fracture half length (Lf ).
Reservoir permeability (k) also must be considered when
fracturing a well. The dimensionless fracture conductivity
(Cf D ) combines the effect of fracture conductivity,
fracture half length, and permeability into one formula:
kf bf
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.1)
Cf D kLf
where kf bf is fracture conductivity (md-ft), k is reservoir
permeability (md), and Lf is fracture half length (ft).
Computer simulations of hydraulically fractured reservoirs,
such as those shown in Chapter 4 (Reservoir Engineering)
indicate that in low-permeability reservoirs, production
can be increased by increasing the fracture length. In
high-permeability reservoirs, however, short fracture
lengths with high conductivity can be effective. The
reservoir engineering chapter also discusses how it is very
important to determine the pressure profile throughout
an entire drainage area to be able to design a FracPac
treatment with the following parameters:
• The fracture length required to bypass the wellbore
damage and prevent the severe pressure drop (this
parameter is optimized for either sand control or
stimulation)
• The fracture conductivity required to minimize the
pressure drop near the wellbore
A FracPac treatment must be carefully designed with a
clear objective: either sand control or stimulation. Although
it is possible to accomplish both, priorities should be set
early in the design process to ensure best results.
IN-SITU STRESSES AROUND
THE WELLBORE
The in-situ stresses within a reservoir are usually in
equilibrium, which allows an undisturbed, stable
condition to exist. If, for any reason, the in-situ forces
change and disturb the stability of the reservoir, a natural
This section focuses on the differences between a
compentent sand and a friable sand, even though both
can result in sand production. In competent sands, a
stress concentration around the wellbore may produce a
shear failure and result in sand production, and continuum
mechanics can be used to describe the problem. However,
in poorly consolidated or friable formations, this principle
cannot be applied.
σvert (Overburden)
correction will occur as an attempt to regain natural
stability. The in-situ stresses within a reservoir can be
represented by three principal stresses: overburden or
vertical stress (v ), minimum horizontal stress (h ), and
maximum horizontal stress (H ). Figure 2.2 provides a
diagram of the in-situ stress relationship. These principal
stresses act on the reservoir rock and can change in
magnitude around the wellbore, causing a stress-concentration zone. Stress-concentration zones can surpass the
yield strength of weak or poorly consolidated formations
and cause them to fail. The severity of the stressconcentration field and the resulting failure mechanisms
are governed by the formation’s mechanical properties.
Understanding the mechanical properties of the formation
is essential in choosing the correct model for predicting
the failure mechanisms that cause formation sands to
move, and subsequent sand production.
Z
σHor.
Y
X
σHor.
Figure 2.2 — The principal stresses act in orthogonal directions
to one another. This relationship can be expressed on an X, Y, Z
coordinate system. The overburden stress acts along the Z axis
parallel to an imaginary line struck between the center of the
wellhead equipment and the center of the earth. The other two
principal stresses, known as horizontal stresses, act along the X
and Y axes.
wellbore and the reservoir pressure determine whether or
not the borehole collapses (wellbore breakout) or fracture
initiation occurs.
Competent Sand
Drilling a circular wellbore through a competent sand
redistributes the in-situ stresses in the formation and creates
a new stress field around the wellbore. If the wellbore is
drilled into a linearly elastic, homogeneous, isotropic
formation, after introducing a vertical wellbore into the
reservoir, the stress state around the wellbore is given by
1
rw2
1
4rw2
3rw4
rr 1 (
)
1
h
2
r2
2 H
r2
r2
rw2
cos2 p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.2)
r2
1
rw2
1
(H h ) 1 (H h )
2
r2
2
3rw4
rw2
1 cos
2
p
. . . . . . . . . . . . . . . . . . . . . . . . (2.3)
r2
r2
The p represents the difference between the wellbore
pressure and the formation pressure. The stresses near the
Wellbore Breakout (Borehole Collapse)
A breakout zone may occur near the wellbore due to the
stress concentration induced by drilling a wellbore. This
breakout zone is created by shear failure of the formation,
which follows a dilation of the borehole. The breakout is
a naturally occuring event that relieves a stress
concentration where the tangential stress ( ) exceeds
the in-situ compressive strength. Although breakouts
relieve the immediate stress concentration within the
borehole, they can evoke sanding when the well is put on
production. The well should be evaluated to determine
whether or not it underwent a breakout failure mode
during drilling. Wellbore breakout can adversely affect a
FracPac treatment by hindering fracture initiation of a
single, planar fracture which is critical to the success of
FracPac. If breakout has occurred, a precise design of the
perforating program becomes crucial and Halliburton
recommends the following:
1. The near-wellbore area should be consolidated prior
to fracture initiation. Consolidation can be performed
by injecting a liquid-resin material into the payzone.
The liquid-resin material increases the cohesion
7
FRACPAC COMPLETION SERVICES
among the particles of the formation sand. An array of
consolidation chemicals has been tested and approved
in Halliburton’s Rock Mechanics Laboratory and are
available for such injection treatments.
2. The breakout zone is generally oriented in the
direction of the minimum horizontal stress, therefore
a 180°-phased perforating program should be
performed. The perforations should be oriented in the
direction of maximum horizontal stress, that is, the
direction of the induced fracture.
3. To ensure that a planar fracture is created, the
maximum allowable pumping rates should be used
with a high-efficiency, viscous treating fluid.
Fracture Initiation
Fracture initiation is a tensile failure mechanism that occurs
when the borehole is pressured, which causes the tangential
stress to become negative and become equal to the tensile
strength of the formation. The following failure criterion
describes the tensile failure mechanism:
pwf t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.4)
Friable Sand
Friable sands are usually cohesionless, and their mechanical
properties are stress dependent. The state of stress around
the wellbore may not conform to the theories of linear
elasticity and continuum mechanics. A zone may develop
around the wellbore that is stressed within plastic yield
limits, thus making the contrast between the minimum and
maximum horizontal stresses negligible. Formation failure
within this plastic zone is a main source of sand production
from the formation. As the plastic zone increases in size,
sand production continues. Friable sands exhibit nonlinear
characteristics, and it is believed that such sands should
be evaluated differently than competent sands. Many
mechanisms become important when evaluting nonlinear,
friable sands. Some of these mechanisms are
• Dilation
• Capillary effect
• Cohesive failure
Once a wellbore or a perforation tunnel is introduced
into a friable sand formation, a plastic zone develops and
formation failure follows, usually because of one of the
mechanisms mentioned above.
8
Production and cyclic loading are the main reasons that
the plastic failure zone expands into the formation. To
prevent the expansion of the plastic failure zone in friable
sands, a circular tunnel (perforation or wellbore) should
not be introduced to the formation. Instead, another
method to deplete the reservoir should be considered,
which is discussed later in this chapter.
FAILURE MECHANISMS
Before a well can be effectively treated for sand production, the failure mechanisms that cause sand production
should be understood. Two types of failure are most
common: mechanical failure due to stress effects and
formation failure due to chemical effects.1
Mechanical Failure Due to Stress Effect
Drilling a wellbore through a formation of rock and sands
introduces a new set of stresses to the area around the
wellbore. The magnitude of these new stresses may be
great enough to cause the formation to fail. Also, during
the course of drilling, completing, or workover operations,
the wellbore is actively and passively loaded with fluids
and pressure, which can initiate formation failure. When
the formation stress model is viewed as a system of polar
coordinates, shearing stresses are imposed on the
formation by a combination of vertical stress, tangential
stress, and radial stress.
Any combination of vertical, tangential, and radial stresses
can contribute to sand production. If the bottomhole
pressure is increased (passive loading), the radial stress
will increase and the tangential stress will decrease. Should
the tangential stress decrease enough, it will change from
compression to tension. Most sedimentary rocks can
withstand massive amounts of compressive force but fail
when exposed to even slight tensile force. As a tensile
failure occurs, cracks begin to open.
If bottomhole pressure is decreased (active loading), such
as when the mud-column weight is lowered or the well is
put on production, the tangential stress in the wellbore
will increase and the radial stress will decrease. Large
drawdown at the wellbore can cause the tangential stress
to exceed the strength of the formation matrix. Formation
sand particles then begin to flow with the well fluids being
produced. Eventually, such sand flow can cause serious
problems, such as plugging gravel packs, plugging and
eroding production hardware, and sometimes eventually
rendering the well inoperable.
The stress effects previously discussed drive four failure
mechanisms that cause the production of formation sand
particles. Figure 2.3 depicts the four failure mechanisms
that cause sand production: tensile failure, shear failure,
cohesive failure, and pore collapse.
The Four Failure Mechanisms
Shear
Stress
τ
σ1
➋
Shear
σ3 Failure
Tensile Failure
The effective stress at the wellbore exceeds the tensile
strength of the formation and causes tensile failure if the
following condition is true:
pwf p t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.5)
where pwf is bottomhole pressure, p is reservoir pressure,
is effective tangential stress at the wellbore, and t is
tensile strength (equal to zero when natural cracks exist).
If the drawdown near the wellbore exceeds the tensile
strength of the formation, tensile failure will result if
➌
Unstable
➊
θ
Cohesive
Failure (C = τo)
Initial
Conditions
➍
Tensile
Failure
Stable
Pore
Collapse
Failure
To
Tension
Co
+ Compression
Effective
Normal
Stress
σ
Figure 2.3 — The four mechanisms that cause sand production
are tensile failure, shear failure, cohesive failure, and pore
collapse. The graph shows shear stress (
) versus effective normal
stress ().
pw t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.6)
Where pw is the pressure differential at the wellbore
and t is the formation tensile strength.
This tensile failure condition may occur when the
production rate is high enough to create a drawdown in
the area local to the wellbore and is high enough to part
the formation. Therefore, the production rate should be
limited so that the drawdown near the wellbore does not
exceed the tensile strength of the formation. FracPac
technology can be applied in situations such as this to
produce more hydrocarbon at a maximum sand-free
production rate. Evaluating the formation to properly
define the purpose of any FracPac treatment is essential
to the success of the treatment. The Halliburton Rock
Mechanics Lab is equipped to evaluate the mechanical
properties of a given formation so that the correct
FracPac treatment is performed.
Shear Failure
Rock failure can cause a reduction in hole size due to
plastic deformation of the formation. Failure can also cause
hole enlargement in brittle formations that are prone to
spalling. Once a wellbore is drilled and the stress-concentration field around the wellbore is established, the formation
will respond either elastically (strong formation) or it will
yield (weak formation). If the formation yields, a plastically
deformed zone begins to develop near the wellbore. This
yield is a formation failure caused by the shear stresses
exerted around the wellbore. Once shear failure has
occurred, both large and small solids will be freed as the
formation deteriorates at the failure plane. Figure 2.3
depicts a graph of shear stress (
) versus effective normal
stress (). The shear strength of a formation is represented
by a straight line on this graph. The slope of the line is the
internal friction of the formation. The intercept of the
line with the shear stress (Y) axis represents the cohesion
among adjoining sand grains of the formation. If this
intercept is extrapolated in the direction of increasing
tension, its intercept with the effective normal stress (X)
axis indicates the tensile strength of the formation.
The Mohr-Coulomb failure criterion can be used to
predict failure conditions for a given formation. This
criterion postulates that failure occurs when the shear
stress at a given plane within the rock reaches a critical
magnitude given by
coh n tan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.7)
where is shear stress, coh is cohesive strength or
cohesion, n is normal stress, or the stress normal to the
shear failure plane, and is the angle of internal friction.
9
FRACPAC COMPLETION SERVICES
Failure Envelope for a Poorly Consolidated
Sand Formation
α
τ
Techniques for dealing with core samples of formations
have been developed, and data analysis is performed to
design a specific treatment for a candidate well. The
Halliburton Rock Mechanics Laboratory has constructed
the Mohr’s circle failure envelopes of many poorly consolidated formations around the world. Figure 2.4 shows a
failure envelope for a poorly consolidated formation where
the shear angle () was determined after the sample failed
under compression.
Cohesive Failure
0
2,000
4,000 6,000 8,000 10,000 12,000
Normal Stresses (psi)
Figure 2.4 — The sample represented by this graph failed under
compression. A failure envelope was developed, and the shear
angle () was determined.
Coulomb-Mohr Failure Criterion
τ = C + σn tan φ
τ
Failure
φ
Friction
Stable
Cohesion
Tension 0
σn Compression
Figure 2.5 — The shear strength of the formation consists of
two components: the contact forces between the grains, or
friction, denoted by the magnitude from the red dashed line to
its intersection with the shear failure line (blue), and the physical
bonds between adjoining grains, known as cohesion. Cohesion is
the magnitude shown from the X axis to the red dashed line.
10
The cohesive failure mechanism is especially important
when formations of poorly consolidated sands are to be
stimulated with FracPac treatments. The cohesive
strength (coh ) is the controlling factor of erosion at any
free surface within the formation. These free surfaces
occur at the perforation tunnels, at the wellbore face in
openhole completions, at the surface of induced hydraulic
fractures or induced shear planes, and at the surfaces
where the pay zone contacts boundary intervals or the
cement contacts the formation. As shown in Figure 2.5,
the shear strength of the formation consists of two
components: the physical bonds between adjoining grains,
or cohesion, and the contact forces and friction between the
grains. Cohesion is generated by two factors: cementing
material and capillary forces among the grains of formation
sand. Sand production and subsequent wellbore instability
begin when the drag force caused by fluid production
becomes great enough to exceed the cohesive strength of
formation sand. Based on a 1-foot deep perforation
tunnel into the formation, sand may be produced if
dp
coh . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.8)
dr
The value coh is determined by extrapolation of the
Mohr’s envelope to zero stress. This type of cohesive
failure is responsible for generating small formation sand
particles known as fines. Low cohesive strength is the
reason for the start of sand production when a pressure
drop near the wellbore is high. At the near-wellbore area
(within 1 foot of the borehole), the pressure drop equal to
the cohesive strength of the formation material defines
the critical production rate without sanding. The rock
mechanics team at Halliburton has developed techniques
to determine the cohesion factor. Based on the results of
cohesion-factor tests, a recommendation for either resincoated proppant or other proppant can be made. The
cohesion factor can also be used to decide whether a
screen should be used with the FracPac completion.
Pore Collapse
Pore Collapse Failure Mechanism
T p . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.9)
where p is reservoir pressure, is effective stress, T is total
stress, and is Biot’s constant (factor that accounts for
the deformation of the rock framework and subsequent
inefficiency in the transmission of pore pressure).
The effect of pore pressure in counteracting the confining
pressure is reduced when inefficiency occurs in the transmission of pressure among the pores. The concept of
effective stress implies that there is no porosity change
under equal variation of pore pressure and confining
pressure. When a FracPac treatment is being designed,
the factor α may be required by the fracture design model.
Techniques have been developed to determine the α factor.
Shear Stress (psi)
The definition of effective stress as the difference between
total stress and pore pressure is given by
ea
Sh
ee
ilur
r fa
pe
n vel o
Pore
Collapse
Normal Stress (psi)
Figure 2.6 — The pore collapse mechanism shows that when
pore pressure decreases, the effective stress increases. When the
effective stress increases, it causes the Mohr’s circle to move to
the right, which may be bounded by a pore collapse failure cap,
as shown by the dashed portion of the blue curve.
The Coulomb failure criterion is expressed in terms of
the effective stress as follows:
coh (n pp) tan . . . . . . . . . . . . . . . . . . . . . . . (2.10)
A graphical depiction of the pore-collapse mechanism is
shown in Figure 2.6. When the pore pressure decreases,
the effective stress increases. When the effective stress
increases, it causes a Mohr’s circle to move to the right,
which may be bounded by a pore-collapse failure cap.
Once pore failure occurs, the damage is permanent and
cannot be repaired. Hydraulic fracturing is a technique
that can be used to bypass this damaged region and get a
well back on production. In many cases this technique
may be more attractive than abandonment or drilling
another well.
Formation Failure Due to Chemical Effect
The main mechanism of formation failure may be due to
effects caused by chemicals that are introduced to the
formation. Engineers may try to model failure mechanisms
of unconsolidated reservoirs using nonlinear elastic models,
elastoplastic models, and poroelastoplastic models, only
to arrive at erroneous conclusions, especially if failure was
caused by chemical effects.
Water adsorption at the clay surfaces of a rock formation
can cause an increase in bulk volume and subsequent
swelling pressure if expansion is restricted. This swelling
pressure can break the adhesive bond of the formation
and disintegrate the formation matrix. Bulk volume and
resultant swelling varies in different types of formations.
Water within the pore spaces of the formation can affect
the formation in three ways:
• It can reduce the magnitude of the internal friction.
• It can reduce the capillary pressure for water-wet rocks.
• It can chemically weaken the cementation material of
the formation.
Experimental data from Halliburton Rock Mechanics
Laboratories show that water affects the compressive
strength and elastic properties of rocks. For example, the
softening factor (Fsoft ) is defined as the ratio of
compressive strength of a dry sample to that of a wet
sample. This softening factor was calculated from a
sandstone sample known to be poorly consolidated and is
given by
coh (dry) 1,799
Fsoft 5.3 . . . . . . . . . . . . . . . . . (2.11)
335
coh (wet)
The cohesive strength of the dry and wet samples were
calculated and
σcoh (dry) ≅ 210 psi
σcoh (wet) ≅ 0 to 20 psi
11
FRACPAC COMPLETION SERVICES
Scanning electron microscope (SEM) and X-ray
diffraction analyses can help determine the cementing
materials such as calcite, dolomite, illite, mixed-layer clay,
chlorite, and others. Any chemicals that could cause the
formation’s cementation to deteriorate should not be
introduced to the formation. Based on the SEM and Xray diffraction analyses, two important conclusions with
respect to the problems of wellbore instability and sand
production have been formulated:
bypass the near-wellbore damage, producing a more
elliptical flow pattern and helping reduce the near-wellbore
drawdown during production.
• Hydrochloric acid (HCl) used as a stimulation fluid
may adversely affect the strength of the formation, if
the cementation material is a carbonate. If the carbonate
is dissolved, the rock structure can fail and cause solids
production. Tests performed at Halliburton’s laboratories
suggest that carbonate may be the cementing materials
of some sandstone formations.
In-Situ Mechanical Properties
• If an appreciable percentage of the rock mineralogy is
clay, the formation should be treated as potentially
water sensitive. Swelling of clay affects the stability of
the rock and indirectly affects sand production.
Therefore, before a FracPac treatment is designed, the
formation should be evaluated for potential formation
failure from chemical effects. Evaluation for possible
chemical effects allows for a more effective stimulation
treatment to be designed.
SANDING TENDENCY AND SAND
PREDICTION
Methods for predicting sanding tendency have been
developed. From past experience with oil and gas wells,
the following trends have emerged:
• Sand production increases with increasing production
rate or decreasing wellhead pressure.
• A sudden change in production rate causes increased
sand production.
• In some cases, once sand has begun to be produced,
sanding becomes uncontrollable.
• The tendency to produce sand is enhanced if the
reservoir is overpressured.
As was discussed previously, sand production can be
triggered by either a mechanical failure of the formation
or a collapse of the cementing material that adversely
reacts to chemicals or fluids pumped into the well.
Creating a short, highly conductive fracture can effectively
12
Several methods are used to predict the occurrence of
sanding. These methods are in-situ mechanical properties,
in-situ stresses and failure criteria, logging methods, and
field observations.
Early sand prediction techniques2 were based on
mechanical properties values and suggested that a
threshold for sanding exists at
G
0.81012 psi 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2.12)
cb
where G is shear modulus (dynamic), and cb is bulk
compressibility (dynamic).
Any formations with values that fall below this criterion
are believed to require sand-control measures. Another
important investigation for sand prediction is the study of
the microstructure of the formation and the stress-strain
characteristics of these formations.
Halliburton’s experience suggests that the sanding threshold
has many limitations and that an empirical formula devised
for one field does not apply to other areas and lithologies.
Extensive laboratory testing of numerous sand-producing
formations has led scientists to believe that examining only
the mechanical properties of the formation is not enough
to predict sand production.
Table 2.1 displays Halliburton’s laboratory-measured
rock properties for various formations with sanding
tendencies. Also displayed are the properties for graded
proppant sand and synthetic friable rocks. Normal ranges
for some of the properties of consolidated sandstones are
also given.3 The samples from Formation A, Formation
B, Formation C, and a sample from an outcropping of
the Antler Sand formation all exhibit Young’s moduli
that are small enough to fall below the G/cb threshold that
indicates sanding. By using laboratory-determined and
estimated parameters, a G/cb value for formation A was
calculated at 0.23 x 1012 psi, well below the cutoff.
By looking at the cores taken from Formation D, a deep
well that had a sanding history, the Young’s moduli of
these consolidated sandstones seem to indicate that G/cb is
Table 2.1 — Comparison of Rock Properties
Depth (ft)
E (106 psi)
Co (psi)
l (psi)
20/40
t (psi)
(deg)
0
29.6
131
51*
Gopher St.
Sand
Formation A
4675
0.27
0.65
1779
210
33**
Formation B
6412
Formation C
0.061
0.88
215.8
0.076
0.87
215.8
0.050
0.14
Synthetic
1st load
0.07
(7% cement
2nd load
0.213
3% clay)
3rd load
0.226
Synthetic
1st load
0.037
(5% cement
2nd load
0.13
5% clay)
3rd load
0.048
0.07
87
0.377
0.625
1037.5
Antler Sand
0
165***
192***
41
230***
200***
41*
20**
Formation D
15,814
4.44
0.28
16,550
8.16
0.19
17,047
4.54
0.33
4.24
0.16
17,171
Normal
0.5 to 11.5
Ranges
* Initial
2,800 to
500 to 3,600
24,000
** Final
*** Extrapolated value
Table 2.2 — Young’s Modulus as a Function of Confining (Stress Antler) Sand
cont (106 psi)
E (106 psi)
cont (106 psi)
E (106 psi)
0.377
1,000
0.377
250
0.478
2,000
0.478
500
0.595
4,000
0.595
0
likely to be well above the sanding threshold. Other
factors play a major role in the failure of these formations.
Antler Sand sample as a function of confining stress. The
increase in modulus yields the following implications:
Another factor that must be considered when using insitu mechanical properties to predict sanding tendency is
the fact that the Young’s modulus (and thus the shear
modulus) of many friable sands increases as confining
stress increases. Table 2.2 shows the modulus for the
• The deeper a formation is, the less likely the formation
is to produce sand, based on this method of sanding
tendency prediction.
• The more that the pressure is drawn down at the wellbore,
the more susceptible the sand face becomes to failure.
13
FRACPAC COMPLETION SERVICES
Stress – Strain of
Poorly Consolidated Sandstone
Stress – Strain
Confined Sandstone
350
3,500
Young's Modulus = 0.061 x 106 psi
Compressive Strength = 215.8 psi
Failure at 7,420 lbs
(3,079 psi)
3,000
250
Axial Pressure (psi)
Axial Load (lb)
300
200
150
100
50
2,500
2,000
Et = 0.133 x 106 psi
1,500
1,000
Et = 0.1 x 106 psi
0
0
0.004
0.008
0.012
Displacement (in.)
0.016
500
0.018
Confining Pressure 500 psi
0
Figure 2.7 — Poorly consolidated sandstone shows a nonlinear
trend when plotted on a stress-strain curve. This trend is much
more pronounced than in harder, consolidated rock. The nonlinearity is believed to be due partly to the limited compressive
force that can be applied when testing unconsolidated sands.
0
Et = 0.121 x 106 psi
Et = 0.087 x 106 psi
Confining Pressure 500 psi
0
Failure at 7,560 lbs
(3,235 psi)
2,500
2,000
Et = 0. 2 x 106 psi
1,500
1,000
Confining Pressure 800 psi
0
.01
.02
.03
Displacement (in.)
.04
.05
Figure 2.8 — When a poorly consolidated sample is confined
and compressive force is applied, the resulting stress-strain curve
more closely follows a linear trend. The sample is this test was
confined with 500 psi of pressure.
Neither of these implications predict how sanding
tendency changes with time, nor do various other
sanding-prediction techniques.
Figure 2.7 shows the stress-strain curve for a poorly
consolidated sandstone. The nonlinearity of this curve
appears to be more pronounced than in consolidated
rocks. Because of lower compressive strengths of poorly
consolidated formations, compressive testing of these
14
0.07
3,000
Axial Pressure (psi)
Axial Pressure (psi)
3,500
1,500
500
0.06
Stress – Strain
Confined Sandstone
Failure detected
at 4,540 lbs
(1,884 psi)
1,000
0.02 0.03 0.04 0.05
Displacement (in.)
Figure 2.9 — Again, a poorly consolidated sample was
confined and subjected to compressive force until it failed.
Confining pressure was 500 psi.
Stress – Strain
Confined Sandstone
2,000
0.01
500
0
0
0.01
0.02
0.03
Displacement (in.)
0.04
0.05
Figure 2.10 — As the confinement force increases, the
stress-strain curve becomes even more linear. The
confining pressure was set at 800 psi in this test.
samples must be performed at lower stress levels than
those of conventional sandstones. Hence, part of the
nonlinearity characteristic is caused by these lower
compressive stresses used in testing. At the present time,
any possible relationship between nonlinearity and sanding
tendency has not been investigated.
Nonlinearity also brings into question the use of a single
Young’s modulus value when modeling fracture growth
Figure 2.11 — The grain-to-grain structure of Antler
Sand in its natural state. Note how closely the grains
contact each other.
Figure 2.13 — The shear-failure plane of natural Antler Sand
after failing at 5,000 psi, under confined test parameters,
shows the radical rearrangement of the grain structure.
Figure 2.12 — Antler Sand was also remolded to be used
in tests. The remolded sand somewhat resembles the
natural, but the close grain contact is absent.
Figure 2.14 — Remolded Antler Sand also failed at 5,000 psi,
under confined conditions. The shear-failure plane is shown.
Again, the grain structure is very perturbed.
in unconsolidated formations,4 as well as the use of
conventional minifrac techniques. The nonlinearity of
unconsolidated formations becomes less pronounced
when the sample is tested under confinement as shown in
Figure 2.8 through Figure 2.10. For the design of a
FracPac treatment, it is important to use an equivalent
Young’s modulus for the pressure range to which the
formation will be exposed.
production problems during the production phase of the
well. A joint research project between Hallilburton and
the Rock Mechanics Consortium at the University of
Oklahoma is studying the difference between natural poorly
consolidated sandstone (from an Antler Sand outcropping)
and a remolded sand as a model for this type of
formation. Figure 2.11 shows the natural Antler Sand
and clearly depicts the grain-to-grain contact structure
that is common to this type of formation. Figure 2.12
shows a sample of Antler Sand that has been remolded
and displays more loosely structured grain contact. Figure
2.13 and Figure 2.14 show the sand grains of each of
these respective formations at their shear planes after the
samples failed under confined conditions at 5,000 psi.
The stress-strain relationship describes the way the
framework of granular material in the formation responds
to the applied load. Also, this relationship reflects whether
or not continuum mechanics principles can be applied.
The granular framework plays an important role in sand
15
FRACPAC COMPLETION SERVICES
Shear Stress vs. Normal Stress
Formation A
8
.30
Shear Stress (kpsi)
Young's Modulus (psi x 106)
Young's Modulus vs. Confining Pressure
.20
.10
0
6
33.3°
50.7°
4
2
0
0
200
400
600
800
Confining Pressure (psi)
1,000
Figure 2.15 — The relationship between Young’s modulus and
the confining pressure shows a linear trend.
-1
0
2
4
6
Shear Stress (kpsi)
8
10
Figure 2.17 — Formation A also shows an initial friction
angle that is greater than 30°.
Shear Stress vs. Normal Stress
Formation B
Shear Stress (kpsi)
3
In-Situ Stresses and Failure Criteria
As mentioned earlier in the chapter, Formation D may
differ from the other formations in Table 2.1 in the type
of mechanism that causes it to fail. The Mohr-Navier
failure theory forms the basis of the most currently used
methods to predict formation failure and sand
production. Other methods have been developed to
estimate cohesion and the angle of internal friction,
which are parameters needed to develop a MohrCoulomb plot.
2
40.7°
1
0
0
1
2
Shear Stress (kpsi)
3
Figure 2.16 — Formation B shows an initial friction angle that
is greater than 30°. A Mohr’s stress analysis, such as the one
shown, can help determine a sandstone’s degree of
consolidation. Sanding tendency, however, requires the
consideration of several other factors.
Table 2.1 and Figure 2.15 through Figure 2.18 show
that poorly consolidated formations, such as those of
Formation A, Formation B, and the Antler Sand
outcropping, may exhibit an initial friction angle that is
greater than 30°. Conclusively, Mohr’s stress analysis,
including consideration of cohesiveness and friction
angle, can provide a means of determining a sandstone’s
degree of consolidation.
Figure 2.19 shows a Mohr’s circle analysis of a formation
at a static, shut-in condition. If a well is subsequently
produced, the change in wellbore pressure causes an
increase in the tangential stress and a decrease in equal
magnitude of the radial stress. Thus, the center of Mohr’s
circle remains stationary, but the radius grows, approaching
the failure line as the wellbore pressure decreases. The
decrease in the pressure at which the Mohr’s circle
intersects the failure line (also shown in Figure 2.19) is
16
the maximum safe drawdown. When the Mohr’s circle
touches or crosses the failure envelope, shear failure and
sand production can be expected.
Uniaxial Compressive Strength
The Mohr-Coulomb failure criteria has been used to
predict sanding tendency based on the uniaxial
compressive strength concept. 7
1 - p = 2u tan + (3 - p) tan2 . . . . . . . . . . . . . (2.13)
Antler Sand Outcropping
10
8
Shear Stress (kpsi)
Because of the loss of interfacial tension and cohesiveness
that can occur with high water cuts, producing a well
with a higher water cut may require a higher intrinsic
shear strength of the formation than is predicted by other
models. A statistical model that extends the Mohr’s circle
analysis was developed to predict sanding in wells along
the Gulf Coast of the U.S., or in similar wells where free
water is being produced. 5 The following failure criteria
were developed.6, 7
Shear Stress vs. Normal Stress
6
33.3°
50.7°
4
2
0
0
2
pdraw = 2cu
for radial flow
6
8
Shear Stress (kpsi)
10
12
Figure 2.18 — The Antler Sand sample shows an initial friction
angle that is greater than 30°.
Equation 2.13 shows that at the borehole, the following
criterion can follow:
pdraw = cu
4
Mohr's Circle at Static Shut-in
τ
for spherical flow
where
We have discussed the in-situ properties of the formation
and what they can mean in the productive life of a well.
Sanding tendency also plays a role in whether the well will
remain productive for a long period. If a well is a likely
candidate for sanding due to poorly consolidated formation,
then measurements must be made to more closely
determine the formation properties. These measurements
are usually made with well-logging tools and equipment.
Well-Logging Methods
Well-logging methods tend to rely heavily on wireline
acoustic logs. Although more detailed methods, such as
those already discussed, are preferred, a simple rule of
thumb based on acoustic travel time through the
formation is often used to distinguish between hard (fast)
and soft (slow) formations. Velocity is a unit commonly
used by geophysicists to measure seismic waves.
Subsurface formation compressional velocity ranges from
Flowing at
∆pM
∆pM
pdraw is drawdown and cu is the uniaxial compressive
strength of the formation.
Static
σr1
σr
σθ
σθ1
σ
Figure 2.19 — The well shown is at static or shut-in conditions.
If the well is later produced, the change in wellbore pressure
causes an increase in tangential stress and a decrease in radial
stress of equal magnitude. The center of Mohr’s circle remains
stationary, but the radius grows. As wellbore pressure decreases,
the failure line is approached by Mohr’s circle.
17
FRACPAC COMPLETION SERVICES
6,000 to 25,000 ft/sec. Shear-wave and compressionalwave interval transit time, or slowness (ts and tc ,
respectively), are measurement units used by acoustic log
analysists and petrophysicists. Slowness is simply the time
required for the acoustic wave to travel a known distance;
on most acoustic tools this distance is 1 ft. Velocity is
expressed in ft/sec, whereas slowness is expressed in
sec/ft. The rule of thumb used in the acoustic log
analysis practice is that formations with ts greater than
160 sec/ft are generally considered soft or slow
formations.8 In sandstone, a ts of 160 s/ft translates to
a tc of about 90 sec/ft.
The 160-sec/ft definition is convenient, since the characteristics of the acoustic wavetrain change significantly at
this time interval; the compressional-wave amplitude
increases and the Stoneley wave becomes controlled by shear
velocity at approximately 160 sec/ft. The shear wave
does not propagate in slow, unconsolidated formations
that are generally the focus of FracPac treatments;
therefore a special, low-frequency dipole acoustic tool
must be run to measure a flexural wave that is propagated
in such formations. The flexural wave travels at the same
velocity as the shear wave at the frequency that it is
transmitted from the tool, so shear-wave slowness is
calculated for slow, unconsolidated formations. Logging
engineers and analysts, who are familiar with acoustic logs,
can look at waveforms being received after traveling
through a formation and immediately recognize whether
the formation is slow (soft) by its unique waveform
signature. The rule of thumb discussed does not
guarantee that a well will have sanding problems, but
does offer a practical, operational definition for
recognizing unconsolidated sands.
Field Observations
In the Gulf of Mexico, operators have set guidelines for
drawdown control for sand production.9 The drawdown
guidelines vary from 500 to 800 psi across the drainage
area including the gravel pack. A different method of
sand control involves limiting the production rate to 15
bbl/day/perf, assuming that 60% of the perforations are
productive, with variable drawdown.
FracPac services use special methods to create induced
fractures and pack them properly to avoid potential
damage to the well by sanding. Tip-screenout fracturing
and the behavior of the formation while fracturing are
crucial to a successful treatment and are discussed in the
following sections.
18
TIP-SCREENOUT FRACTURING
The-tip screenout fracturing (TSO) technique applies
hydraulic-fracturing technology to create a wide, short
fracture that yields high production rates with reduced
pressure drop.10 TSO can be a highly effective technique
in controlling sand and stimulating maximum
production from weak formations.
Ideal candidates for hydraulic fracturing with planned
screenout include the following types of wells:
• Wells that require a limited fracture size or a fracture
that just bypasses wellbore damage. These may be wells
with no boundaries for fracture-height restriction, wells
with a nearby aquifer, injection wells, or slim holes
spaced close together in a field.
• Formations that are not candidates for matrix acidizing.
• Reservoirs with moderate to high permeabilities, with
or without formation damage.
• Wells that require restricted production rates for
sand control (or otherwise need prevention from
formation failure).
• Wells that have been previously gravel packed and have
lost production because of pore collapse and plugging
of the gravel pack due to fines migration.
TSO fracturing design is discussed in detail in the following
sections from a rock mechanics perspective and includes
discussion of fracture geometry, fracturing pressure
analysis, deviated and horizontal well applications, and
perforating design.
Fracture Geometry
The design of fracture height, width, length, and
conductivity should be determined before the stimulation
is performed. The following aspects of fracture geometry
are important in making design decisions.
Fracture Height
10
BHTPC Closure (kpsi)
Fracture height should be restricted so that a wide
fracture is created, which is a key factor in the success with
tip-screenout-fracturing applications. Knowledge of the
in-situ stress profile in the payzone and the surrounding
boundaries is crucial to sound TSO treatment design. In
formations that have no boundaries to the pay zone, a
penny fracture usually results. The mechanical properties
and the in-situ stress profile can be used to determine
the injection rate needed to contain the fracture within
the pay zone.
Typical Pressure Response for Fracturing
with Planned Screenout
1
Fracture Width
Fracture width development of TSO fractures in unconsolidated formations does not follow the analysis conventions
of hydraulic fracturing in hard rock. Conventional hydraulic
fracturing analysis has a width equation that applies to the
linear elastic region of the stress-strain relationship of a
given rock. Unconsolidated sands, however, exhibit
highly nonlinear behavior when stress is applied to them.
When a soft formation is hydraulically fractured, the net
treatment pressure in the fracture could be within the
stress-dependent Young’s modulus region of the stressstrain relationship. Because this area is small, it can be
ignored when analyzing a fracture in conventional rock;
however, it should not be neglected when an unconsolidated
sand is hydraulically fractured. In sands, there is a zone
within a critical distance from the fracture in which
deformation is taking place. Beyond this critical zone,
the rock does not experience the applied stress. Thus the
formation beyond the critical zone near the fracture does not
exert any elastic rebound toward the fracture when fluid
pressure is released in the fracture. The combined effects
of sand compaction and the stress-dependent Young’s
modulus result in a wide fracture being created in
unconsolidated sands. A general equation was developed
that describes the stress-strain relationship of rocks that
exhibit nonlinear behavior under load:12
2
E∞n - O tan-1 n . . . . . . . . . . . . . . . . . . . (2.14)
O
where E∞ is stress-strain slope approached as stress increases,
and O is the negative of the stress-axis intercept of the
straight line being approached. Additional parameters
which appear in variations of the equation are O is a
divisor of the strain, n is an exponent, n is strain
(normal), and c is a compressibility.
0
1
10
Time (min)
100
Figure 2.20 — The pressure response for fracturing with a
planned screenout shows events during the treatment that are
typical such as pressure buildup, fluid leakoff, and screenout.
Fracture Length and Conductivity
Fracture length and conductivity for tip-screenout designs
of FracPac should be optimized using a reservoir simulator.
A reservoir simulator can also be used to predict the
maximum pressure-drop region around the wellbore. The
fracture length and conductivity can then be designed to
effectively bypass the maximum pressure-drop region or
the near-wellbore damage region.
Fracturing Pressure Analysis
Stimulation treatment pressure is monitored during the
job and used to analyze fracture-growth behavior. Plots of
pressure versus time at a given injection rate are data that
Halliburton obtains from a fracturing treatment, and
these plots are carefully analyzed to evaluate a fracturing
treatment (Figure 2.20). When a tip screenout occurs,
the treatment pressure increases with time if the injection
rate is constant. An increase in pressure can also be caused
by other mechanisms and should not be confused with
the tip screenout during the treatment.
19
FRACPAC COMPLETION SERVICES
Pressure behavior during a minifrac test (run before the
fracturing treatment) can provide a valuable reference
when analyzing the pressure data acquired from the main
fracturing job. A minifrac test must be performed, not
only to collect fluid-leakoff data coefficients, but also to be
used as a reference for analyzing pressure-versus-time data.
Three mechanisms exist that are known to cause a rapid
pressure increase with time during a fracturing treatment:
near-wellbore or perforation restriction, complex fracture
geometry, and screenout mode.
Near-Wellbore Restriction, Perforation
Restriction, or Both
It is a well-known phenomenon in hydraulic fracturing
that the treatment pressure will increase when a nearwellbore restriction or a perforation restriction exists. In
some cases, a combination of both of these restrictions is
present. It is very important to differentiate a tip screenout
from a near-wellbore screenout. Experienced engineers
and fracturing practitioners can differentiate between tip
screenout and near-wellbore screenout, if they consider all
of the available well data to reach a conclusion. However,
controversy among fracturing experts exists, which suggests
that many screenouts that are considered tip screenouts
are actually caused by blockage at or near the perforations.11
It was also suggested that a tip screenout can be controlled
with proppant scheduling and fluid rheology, and not by
pad volume. Step-up tests, step-down tests, or both can be
used to evaluate the nature of the restriction, making it
possible to differentiate between perforation restrictions
or near-wellbore restrictions. Identifying the nature of
restriction can help modify the job design to properly
handle specific well conditions.
Fracture Geometry
An increasing pressure trend may be caused by fracture
geometry such as restricted fracture height, multiple
fracture strands, and fractures that have reoriented
themselves. The pressure response during a minifrac test
can be used to help analyze the data during a fracturing
treatment in which the pressure response is suspected of
being altered by unusual or complex fracture geometry.
20
Screenout Mode
To analyze a pressure response, the traditional Nolte-type
screenout mode is used.12 The Nolte-type analysis assumes
that if the slope is equal to 1 on a plot of net pressure
versus time, a tip screenout has occurred. This pressure
response is similar to the storage effect that is caused by
fluid compressibility during well testing. To understand
this behavior, it is necessary to derive the following equation
based on constant liquid compressibility:
q dt
c V dp
q
log plog log t . . . . . . . . . . . . . . . . . . . . . . . (2.15)
cV
A plot of p versus t on a log-log scale graph should
yield a straight line with a slope of 1. The equation above
is based on the following conditions:
• Injection rate (q) is constant.
• Fluid compressibility (c) is constant over a given
pressure range (p).
• V is the volume of the system, which is assumed to be
constant over the time span (t).
• The system is saturated with a fluid of constant
compressibility (c).
Note that ∆p in the equation is defined as the difference
between two pressures within the pressurization time span.
Formations that exhibit significant nonlinearity violate an
implicit assumption in current fracturing-pressure analysis
techniques. An example of this violation is the curvature
exhibited by a number of unconventional formations.
This curvature distorts the slope of the log of net pressure
versus the log of injection time or volume plots. Also
suggested was that by substituting ∆ or ∆[ (1−v 2)] for
pn in the various net-pressure plotting techniques, most
valid guidelines continue to be valid for the new plots.4
Nonlinear formations may also exhibit significant
hysteresis, which is apparently an effect caused by the
same mechanisms as the nonlinearity. Since minifrac
analysis is performed during a phase in which the
formation is relaxing, the validity of the nonlinearity and
the hysteresis effects are questionable. The nonlinearity
and hysteresis may help explain the anomalous pressure
decline observed in other formations such as coal seams.13
FRACTURING CHARACTERISTICS
400 psi
To understand the behavior of poorly consolidated
formations while undergoing fracturing at Halliburton’s
Rock Mechanics Laboratory, large-scale samples of Antler
Sand were fractured with triaxial stress applied to them.
An ongoing research program was initiated to answer the
following questions:
400 psi
• Does fracturing poorly consolidated formations follow
the conventional theory of creating a singular fracture
perpendicular to the minimum horizontal stress?
• At what horizontal-stress contrast is the induced
fracture not governed by the stress-field directions?
200 psi
300 psi
300 psi
• Is the fracture direction governed by the orientation of
the perforations, and if so, what perforation phasing is
most effective?
• Does the fracture geometry in horizontal and deviated
wells drilled in poorly consolidated formations follow the
same behavior that is observed in competent formations?
200 psi
Figure 2.21 — The vertical well shown was drilled into a poorly
consolidated formation, and a vertical fracture was created.
Telltale signs of high fluid leakoff are noticeable.
Figure 2.21 shows a vertical well drilled into a poorly
consolidated formation. A vertical fracture was created
and propagated. Note that the fluid leakoff was high and
very noticeable. Figure 2.22 shows a similar test
performed with a different stress field imposed. This
research is ongoing and will address other important
concerns of fracturing poorly consolidated formations.
1,000 psi
Deviated and Horizontal Well
Applications
The primary rock mechanics issue of fracturing horizontal
and deviated wells in poorly consolidated formations is
the fracture geometry at and near the wellbore. Fracture
initiation plays a critical role in how the fracture geometry
pattern is created near the wellbore.
Until fracturing begins, the formation remains in a static
situation, or in equilibrium, and a balance of related
radial, vertical, and tangential in-situ forces exists around
the wellbore. Both theory and experiments indicate that
fracture initiation in horizontal and deviated wells does
not mimic fracture initiation in vertical wells.14 Unlike
conventional wells, and the axial (normal) fractures that
occur in them, horizontal-well fractures do not always
initiate perpendicular to the minimum horizontal stress.
A degree of shear failure, which is not present in fractures
of vertical wells, accompanies the initiation and extension
600 psi
500 psi
Figure 2.22 — Another vertical well was drilled into this poorly
consolidated formation with a different stress field. The increase
in overburden caused the fracture to extend farther horizontally
into the formation with less vertical growth.
21
FRACPAC COMPLETION SERVICES
of almost all fractures in wells that deviate from vertical
or are horizontal. Single or multiple fractures are common
within these wells, and the fracture behavior is dependent
on wellbore orientation versus the in-situ stresses of the
formation that it traverses.
1,400
psi
3,000 psi
Single Fractures
si
2,500 p
2,500 p
si
Figure 2.23 — The fracture in this test initiated in a longitudinal
orientation. The wellbore was drilled in the direction of maximum
horizontal stress, causing the fracture to propagate perpendicular
to the minimum horizontal stress. This alignment with the borehole
seems to be optimum, since the fracture initiated immediately
behind the casing.
Results from experiments at Halliburton reveal a tendency
of single, planar fractures to form in horizontal wells
drilled in the direction of one of the principal horizontal
stresses.15 Figure 2.23 shows such a fracture that initiated
longitudinally, i.e., aligned with the borehole. This
experimental wellbore was drilled in the direction of the
maximum horizontal stress, causing the fracture to initiate
perpendicular to the minimum horizontal stress. This
orientation seems to be optimum, since the induced
fracture initiates in alignment with the borehole, immediately behind the casing. There exists some tolerance in the
wellbore azimuth, which allows the borehole to vary as
much as 10° from the true perpendicular to the
minimum horizontal stress and still promote good
fracture initiation. Single, planar fractures are by far the
most preferred geometry, since any other type of fractures
caused by improper borehole direction require higher
initiation pressures and create complicated fluid flow
paths into the wellbore.
1,400 psi
Multiple Fractures Near the Wellbore
2,500 psi
2,500 psi
3,000
psi
1,400 psi
Figure 2.24 — Multiple fractures that form in horizontal or
inclined wells generally have openings that are smaller than those
created by a single, planar fracture. Such narrow openings can
create high treatment pressures and can trigger early screenout.
22
The direction of the wellbore and the angle that it
intersects the principal horizontal stresses can cause
multiple fracture geometries to be formed. Multiple
fracture systems are very erratic in the way they form and
present complex fluid flow problems that hinder a
successful stimulation treatment.
Multiple fractures, such as those shown in Figure 2.24,
that form in inclined or horizontal wells have openings to
the wellbore that are generally smaller in width than the
opening created by single, planar fractures. Such narrow
openings can cause high treatment pressures and can
trigger early screenout. Early screenout occurs when
proppant jams in a narrow passage or bend before it
reaches the leading tip of the fracture. An unpropped
section of the fracture is left from the tip to the bridging
point. Therefore, narrow openings of multiple-fracture
systems near the wellbore are not desirable, and any
practices that cause this should be avoided whenever
possible. Special design considerations must be applied in
cases where these conditions cannot be avoided.
Perforation Design
Perforations play a critical role in achieving a successful
fracturing treatment performed in vertical and horizontal
wells. Perforations, and ultimately fracture initiation,
determine the communication path between the wellbore
and the fracture plane that extends from the wellbore into
the formation. Good perforation design and implementation can help prevent nonplanar fracture geometries such
as multiple strands, reorientations, T-shapes, and other
complex systems from forming. Serious impedence in the
form of narrow multiple fractures, high fluid leakoff, and
increased friction pressure in the fracture can result from
nonplanar fracture geometries forming.
To minimize these potential problems and their effect on
a successful fracturing stimulation, a perforation design
should be in phase with the anticipated fracture direction
to help ensure that the following events occur:
• A fracture propagates perpendicular to the minimum horizontal stress, which gives a maximum
fracture width.
• A single fracture propagates.
• Fracture initiation and extension pressures are reduced,
which is desirable in any fracturing treatment.
Fortunately, this aligned perforation orientation is in
agreement with treatment methods that best inhibit sand
production. Aligned perforations also offer the advantage
of establishing the most stable perforation tunnels possible
since they are oriented in the direction of maximum
horizontal stress and the anticipated direction of an induced
hydraulic fracture. For a horizontal well, perforations
should be oriented at the upper and lower sides of the
wellbore and possibly oriented in the direction of the
anticipated fracture as shown in Figure 2.25.
For poorly consolidated formations, the magnitudes of
the horizontal stresses may be approximately equal in
value. This suggests that an induced hydraulic fracture is
directed by perforation orientation rather than in-situ
stress orientation. A 180° perforation phasing should be
considered in unconsolidated formations with a stress
field of this nature.
When a wellbore penetrates a competent formation, a
stress concentration field will be created around it. If this
stress field magnitude surpasses the formation strength,
failure occurs and can initiate sand production, which
can progress throughout the reservoir. To eliminate stress
concentrations, ideally a wellbore or perforation tunnel
σv
Single
Fracture
Single
Fracture
f
• Single
• T-shaped
• Multiple
σHmin
σHmax
• Multiple (at wellbore)
• Reorientation
• Reorientation
• Multiple Fracture (away from wellbore)
Figure 2.25 — In horizontal wells, the perforations should be
oriented at the upper and lower sides of the wellbore, and in the
direction of the anticipated fracture, if possible. Characteristic
fracture geometries for other wellbore orientations are also shown.
should not be introduced into a formation. If possible,
another method to deplete the reservoir should be used.
If sand production is a major concern for a poorly
consolidated formation that is to be treated, an
innovative technique may be used for sand control. This
technique is not reliant on a circular borehole being
introduced to the formation. However, the hydrocarbonbearing formation is accessed by a hydraulic fracture that
extends from a remote wellbore. This method is used
primarily with horizontal wellbores, but it is also effective
when used in vertical wells.
Vertical Wells
For maximum sand control, the vertical well can be
drilled very close to, but not into, the unconsolidated
sand interval. A 1- to 5-ft interval is then perforated into
a formation layer that bounds the pay zone, and a
carefully designed fracture is created.
23
FRACPAC COMPLETION SERVICES
Horizontal Wells
In horizontal wells, where maximum sand control is
desired, the following technique can be used to avoid
drilling or perforating into an unconsolidated sand:
1. A horizontal borehole is drilled into a boundary formation adjacent to the poorly consolidated sand reservoir.
2. Oriented perforating is performed with zero phasing;
i.e., the charges are aimed toward the lower side of the
horizontal well.
3. A hydrofracture is initiated, which should be designed
as a tip-screenout treatment. Resin-coated proppant is
used throughout the entire job.
The previously mentioned techniques to control sand
production are based on the following observations and
concerns:
• When compared to a vertical well, the horizontal well
reduces the drawdown for a given production rate. The
drawdown places increased deviatory stress on the
formation, which can cause formation failure and
ensuing sand production if the increased stress exceeds
the formation strength.
• Creating a conductive fracture transforms the radial
flow into linear flow before reaching the wellbore and
thus reduces the fluid convergence that is present with
radial flow. Ultimately, the drawdown is decreased for
a given production rate.
• Formation failure begins near the wellbore due to the
stress concentration created after a wellbore is drilled
into the formation. The aforementioned drilling
technique is an innovative, indirect method of
fracturing into the producing zone that avoids
penetrating a structurally weak formation and inducing
stresses that can cause failure and sand production.
In addition to using oriented perforations to control sand
production, oriented hydrajetting can help create a single,
continuous initiation path for fracturing. In unconsolidated
formations, a prefracturing sand-consolidation stage can
be pumped to help initiate a single fracture, rather than
ballooning a cavity into the formation.
MEASURING IN-SITU STRESSES
As discussed previously, the in-situ stresses and mechanical
properties of the formation are crucial in evaluating
sanding tendency and in the design of a FracPac treatment
24
for oil and gas wells. Several methods are available to
measure the magnitude and direction of the in-situ stresses
in the formation. The primary methods used are microfrac
testing, extensometer measurement, and anelastic strain
recovery. Other methods of measuring in-situ stresses
involve the measurement of borehole breakout, the Kaiser
effect, downhole imaging tools, and acoustic logging tools.
Microfrac Testing
Microfrac testing procedures are true to their namesake in
that they create a very small (micro) fracture at the desired
depth within a well.16, 17 This procedure is performed by
injecting a small volume, typically 1 to 2 bbl, of fracturing
fluid into a limited area of the wellbore that is isolated
between a packer and the bottom of a vertical section of
the well. The packed-off area is then fractured by injecting
fracturing fluid at a pressure that is sufficient to fracture
the well. The magnitude of the minimum horizontal stress
is determined by pressure fall-off after fluid injection has
stopped. An oriented core from the bottom of the well is
retrieved, studied, and retained. The core may be used for
Anelastic Strain Recovery (ASR) tests.
Measurements of the microfrac core generally yield stress
directions, with the direction of minimum horizontal
stress being perpendicular to the direction of the induced
fracture. Microfrac procedures can be performed in either
cased hole or open hole, with open hole being the
preferred method, since it is possible to recover a
fractured core sample.
Microfrac-THE Tool Test
Microfrac testing can be performed in combination with
the Total-Halliburton Extensometer (THE) tool, which
is a high-precision, multi-arm caliper. This tool is coupled
with orientation-, pressure-, and temperature-measuring
devices. Also, straddle packers are part of this tool and
enable it to isolate individual zones and test them. During
the test, the deformation of the wellbore is measured.
Deformation readings are taken before, during, and after
hydraulic fracture initiation and propagation. These data
are analyzed to obtain the in-situ stress field, determine
formation mechanical properties, and measure fractureclosure pressure and fracture width.18, 19
Anelastic Strain Recovery
Wireline Testing
The ASR testing method is used to predict the direction
of the in-situ stresses in the formation. This method is
based on the theory that a core relaxes when the in-situ
stresses are removed from it.20 The amount of relaxation is
related to time and is directly related to the magnitude
and direction of the downhole stresses that were imposed
on the core. To perform the ASR procedure, an oriented
core must be available. An instrument capable of
measuring displacements with a resolution of less than one
microstrain is used for ASR testing.
Directional acoustic measuring devices, such as the
circumferential acoustic scanning tool (CAST) and the
borehole televiewer (BHTV), can be run on wireline to
observe natural and induced fractures that intersect the
borehole wall.6, 7 These tools are deployed on a wireline,
and both have high-frequency transmitter/receiver heads
that rotate about the axis of the tool. As the head rotates,
it transmits sound waves that travel to the borehole wall,
reflect, and return to the receivers on the rotating head.
Reflections off smooth areas of the wellbore wall appear
as light-colored areas in the resulting image, whereas
fractures and rough areas appear as dark-colored areas.
The orientation of the rotating transmitter/receiver head
can be related to azimuth at any instant thus yielding
directional fracture information.
The ASR method is very reliant on time and rock properties.
A stabilization time is reached, at which relaxation can no
longer be measured, so the procedure is usually performed
at the wellsite. ASR testing can be performed on core
specimens from vertical or inclined wells.
Other Testing
Various techniques are used to directly and indirectly
measure the in-situ stress field around the proposed
borehole. Data from regional geological surveys may be
consulted, or borehole breakout data may be studied.
Borehole breakout is measured with an X-Y caliper tool. The
borehole tends to break out, or become elliptical, in the
direction parallel to the minimum horizontal stress.21, 22
Stress magnitude in competent formations may be
estimated by running a long-spaced sonic logging tool in
the vertical section of the well. From sonic measurements,
logs can be produced that display a combination of
formation bulk density and an estimate of Poisson’s ratio
and that are useful in indirectly calculating the stress
values in the formation. These logs can be calibrated from
microfrac data obtained in one or more intervals and used
to estimate the minimum horizontal stress in another
interval where microfrac was not run.
The Kaiser Effect
A sustained interest in the Kaiser effect for geomaterials
has existed for quite some time.23 The Kaiser effect involves
the emission of miniscule acoustic signals by core grains
when a stress is applied to the core. The effect forms the
basis of a method for determining the stress within a core
sample. In the test, the core is subjected to a sequence of
stresses. During the first cycle of loading, a high-frequency
sound burst is emitted. In subsequent cycles, however,
there is an absence of these emissions until the previous
maximum stress is surpassed. A marked increase in
emission then begins. This increase has been termed the
Kaiser peak, or Kaiser step, and is believed to hold a stress
history of the material being tested. By using this technique
to test geomaterials, the first cycle of uniaxial loading
could yield the in-situ stress level that once was placed on
the core. This method of testing determines stress directly
rather than measuring strain and deducing stress from it.
25
FRACPAC COMPLETION SERVICES
NOMENCLATURE
= Angle of friction (degrees)
Fsoft = factor, softening
= stress, shear (psi)
G = modulus, shear (dynamic)
= stress, effective (psi)
k = permeability, reservoir (md)
= Biot’s constant
kf bf = conductivity, fracture (md-ft)
O = negative of stress-axis intercept
Lf = half-length, fracture (ft)
= stress, tangent, effective (psi)
p = pressure, reservoir
= stress, tangent, effective
0 = divisor of strain
coh = strength, cohesive, or cohesion
pdraw = pressure, drawdown (psi)
pp = pressure, formation pore (psi)
pwf = pressure, bottomhole, flowing
H = stress, horizontal, maximum (psi)
q = injection rate
h = stress, horizontal, minimum (psi)
r = radius (ft)
n = stress, normal (psi)
rw = radius, wellbore (ft)
n = strain, normal
V = volume
p = pressure drop or differential
pu = pressure differential at the wellbore
rr = stress, radical, effective (psi)
t = strength, formation tensile
T = stress, total (psi)
t = time span or time differential
tc = slowness, acoustic, formation compressional
ts = slowness, acoustic, formation shear
u = stress, uniaxial (psi)
v = stress, vertical, or overburden (psi)
C = compressibility, fluid
Cb = compressibility, bulk (dynamic)
Cf D = conductivity, fracture, dimensionless
Cu = strength, uniaxial, compressive (psi)
26
E∞ = slope, stress-strain
REFERENCES
1. Abass, H.H., et al.: “Stimulating Weak Formations Using New
Hydraulic Fracturing and Sand Control Approaches,” Paper SPE
25494, SPE Production Operations Symposium, Oklahoma City,
Oklahoma, March 21-23, 1993.
2. Tixier, M.P., Loveless, G.W., and Anderson, R.A.: “Estimation of
Formation Strength From the Mechanical Properties Log,” JPT
(March 1975) 283-293.
3. Stimulation Design, Halliburton Services (1989), Section 6, 8-9.
4. Poulsen, D.K.. and Abass, H.H.: “Hydraulic Fracture Modeling in
Formations Exhibiting Stress- Dependent Mechanical Properties,”
Paper SPE 26599, SPE Annual Technical Conference and
Exhibition, Houston, Texas, October 3-6, 1993.
5. Ghalambor, A., et al.: “Predicting Sand Production in U.S. Gulf
Coast Gas Wells Producing Free Water, “ JPT (December 1989)
1336-43.
6. Jeager. J.C., and Cook, N.G.W.: “Fundamentals of Rock Mechanics,”
Chapman and Hall Ltd. 11 New Fettar Lane, London EC4P 4EE,
1971.
7. Rinses, R., Bratli, R.K., and Horsrud, P.: “Sand Stresses Around a
Wellbore,” SPEJ (December 1982) 883-898.
8. Sharbak, David: personal communication, 1993.
9. Fahel, R.A., and Brienen, J.: “How Gulf of Mexico Operators Design
and Perform Sand Control,” World Oil (September 1993) 105-109.
17. Kuhlman, R.D.: “MicroFrac Tests Optimize Frac Jobs,” Oil & Gas J.
(January 22, 1990) 45- 49.
18. Kuhlman, R.D., Heemstra, T.R., Ray, T.G., Lin, P., and Charlez,
P.A.: “Field Tests of Downhole Extensometer Used to Obtain
Formation In-Situ Stress Data,” Paper SPE 25905, SPE Joint
Rocky Mountain Regional /Low-Permeability Reservoir
Symposium, Denver, Colorado, April 26-28, 1993.
19. Lin, P., and Ray, T.G.: “A New Method to Determine In-Situ
Stress Directions and In-Situ Formation Rock Properties During a
Microfrac Test,” Paper SPE 26600, SPE Annual Technical
Conference and Exhibition, Houston, Texas, October 3-6, 1993.
20. El Rabaa, A.W.M. and Meadows, D.L.: “Laboratory and Field
Applications of the Strain Relaxation Method,” Paper SPE 15072,
SPE Regional Meeting, Oakland, California, April 2-4, 1986.
21. Miller, W.K. II, Peterson, R.E., Stevens, J.E., Lackey, C.B., and
Harrison, C.W.: “In-Situ Stress Profiling and Prediction of
Hydraulic Fracture Azimuth for the Canyon Sands Formation,
Sonora and Sawyer Fields, Sutton County, Texas,” Paper SPE
21848, SPE Regional Meeting and Low-Permeabilities Seminar,
Denver, Colorado, April 15-17, 1991.
22. Yale, D.P., Strubhar, M.K., and El Rabaa, A.W.: “Determination
of Hydraulic Fracture Direction, San Juan Basin, New Mexico,”
Paper SPE 25466, SPE Production Operations Symposium,
Oklahoma City, Oklahoma, March 21-23, 1993.
23. Holcomb, D.J.: “General Theory of the Kaiser Effect,”
International Journal of Rock Mechanics and Mineral Sciences,
(special issue, February 21, 1993) 1-2.
10. Smith, M.B.: “Stimulation Design for Short, Precise Hydraulic
Fractures,” SPEJ (June 1985) 371- 379.
11. Barree, R.D.: “A New Look at Fracture Tip Screenout Behavior,”
Paper SPE 18955, SPE Joint Rocky Mountain Regional
Low-Permeability Reservoir Symposium, Denver, Colorado,
March 6-8, 1989.
12. Nolte, K.G., and Smith, M.P.: “Interpretation of Fracturing
Pressures,” Paper SPE 8297, SPE Annual Technical Conference,
Las Vegas, Nevada, September 23-26, 1979.
13. Soliman, M.Y., Kuhlman, R.D., and Poulsen, D.K.: “Minifrac
Analysis for Heterogeneous Reservoirs,” Paper CIM/SPE 90-5,
CIM/SPE International Technical Meeting, Calgary, Alberta,
Canada, June 10-13, 1990.
14. Daneshy, A.A.: “The Study of Inclined Hydraulic Fractures,” SPEJ
(April 1973) 61-68.
15. Abass, H.H., Hedayati, S., and Meadows, D.L.: “Nonplanar
Fracture Propagation from a Horizontal Well-Experimental
Study,” SPE 24823, SPE Technical Conference and Exhibition,
Washington, D.C., October 4-7, 1992.
16. Daneshy, A.A., Chisolm, P.T., Glusher, G.L., and Magee, D.A.:
“In-Situ Stress Measurements During Drilling,” JPT (August 1986)
891-898.
27
FRACPAC COMPLETION SERVICES
28
Chapter 3
INTRODUCTION
Several gravel-packing techniques are
available and are very effective. Each of
these techniques has special advantages
and is designed for unique applications.
This chapter discusses how the gravelpacking process is applied and the
many techniques that are available to
meet various sand control needs.
THE GRAVEL-PACKING
PROCESS
Cased hole gravel packing has evolved
into a two-stage process. The evolution
to two processes was driven by the
realization that gravel packs must
achieve and sustain high productivity
for a well with sanding tendencies. To
accomplish these productivity goals, both
the perforations and the area external to
the wellbore must be packed with sized
gravel in a way that provides fluid
communication from the undamaged
formation to the wellbore. Also, the
gravel pack must provide effective sand
control by physically supporting the
formation and by blocking produced
formation sand from reaching the
wellbore. A complete pack that is free of
voids is one of the most effective sand
control measures available to operators.
The annular portion (area between the
gravel-pack screen and the casing) of
the pack alone cannot sustain high-rate
well productivity over a long period.
The external gravel pack (the area either
in a perforation tunnel or fracture that
extends past any near-wellbore damage)
is a key to prolonged trouble-free
production, but cannot, by itself,
provide sand control. It is obvious that
both the internal (annular) gravel pack
and the external gravel pack should be
designed and placed correctly and
should work in combination to provide
high productivity from the well throughout the economic life of the reservoir.
Sand
Control
Methods
Perforation Packing
Since the quality of the external gravel
pack and the packed perforations is
critical to high well productivity, efforts
to improve this area of gravel packing
have been extensive. Fluid leakoff is a
key element to successful perforation
packing and sand transport to the
external pack. Unless the carrier fluid
flows through the perforations and into
the formation, gravel cannot be transported and packed into the perforation
tunnels and subsequently into the
fractures, if a fracture stimulation is
being performed. The packed perforation
tunnels and fractures are the vital link
from an area of undamaged formation
permeability to the wellbore.
Several methods have been developed to
enhance fluid leakoff to the formation,
thus improving external gravel pack
placement. Improvements to sand slurry
flow, either with fracture stimulation
or without stimulation, have been
devised. These improved techniques can
be performed with the gravel pack screen
and other downhole equipment in place
or before the screen is placed across the
perforated interval. The preferred
packing methods, based on frequency
of use, are either prepacking or placing
the external pack with screens in place,
combined with some form of stimulation such as fracturing or acidizing.
29
FRACPAC COMPLETION SERVICES
Fluid Loss Control
One successful method to improve external gravel packing
consists of spotting a sand slurry into the open perforations
immediately following underbalanced tubing-conveyed
perforating. A volume of sand slurry sized to fill the
perforations and the casing interval at the perforations
and some excess are pumped before retrieving the TCP
guns from the well. Sand-control measures are enhanced
by packing the sand into clean perforation tunnels. Also,
fluid loss control is established by packing the casing ID
with gravel. Later, when the gravel is washed from the
casing to allow screen placement, lost circulation material
(LCM) can be placed above the gravel-filled perforated
interval. LCM placed against the outside of perforation
tunnels makes cleanup much easier. Removal of LCM
can be difficult if it is a combination of particulates
(solids) and polymers; failure to remove such solids before
the external gravel pack is placed can consume space that
is needed for highly permeable gravel.
LCM that is free of solids and contains breaker systems
can control fluid loss without filling the perforations and
the area external to the casing with unwanted solids. These
solids deter the formation of an effective gravel pack.
Solids-free LCM has been used successfully in many areas
including the North Sea. Care must be taken during the
washout portion of the procedure to maintain
overbalance conditions to minimize removal of the nearwellbore packing already placed in the perforation tunnels.
Disturbance of the gravel pack near the wellbore can have
detrimental effects on productivity. Fluid losses caused by
the washdown procedure and high LCM loss during
circulation of the well are disadvantages of this method,
as is the significant amount of rig time required to
perform this procedure.
Perforation Packing With
Acid-Prepack Method
The acid-prepack method is a combination stimulation and
sand-control procedure that helps yield high
productivities from wells that require sand control. Acidprepack is often the method of choice for external gravel
pack placement and has proven to be a productive,
reliable, and cost-effective treatment in wells all over the
world. Operators in Malaysia, the Gulf of Mexico, and
China rely on the acid-prepack method to provide the
high production rates so critical to the economic success of
wells in those regions.
30
The acid-prepack method combines the stimulation
benefits of a hydrofluoric (HF) acidizing treatment with the
sand-control benefits of packing the perforations and the
region external to the wellbore. Alternating stages of acid
and gravel slurry are pumped during the treatment. The
acid dissolves the damage that is left in the formation from
drilling fluids, perforating, completion fluids, and LCM.
Of the types of damage that are removed from the
perforations and formation, removal of LCM from the
perforations is most critical. The perforations should be
cleaned with HF and then packed with gravel to ensure
that the external pack is connected to the internal pack. If
the perforations are not cleaned and then packed with pack
sand, formation sand can flow into the perforation tunnels
when the gravel pack stabilizes during initial production.
One of the most beneficial aspects of the acid-prepack
method of sand control is the combination of damage
removal or breakdown by the acid and the excellent sand
control initiated by the external gravel pack. With damage
removed from the formation face, the perforations readily
accept carrier fluids that quickly leak off and allow the
gravel to pack in the perforation tunnels. This acid and
slurry process is repeated several times. As the perforations
fill with gravel and the formation is penetrated by the
gelled gravel pack fluids, the viscous gel causes flow
resistance in the formation pores. This resistance diverts
the subsequent stages of acid to other untreated areas of the
same perforation, or other perforations, and more uniformly
stimulates the entire interval of interest. Damage removal
and perforation packing are then evenly distributed over
the entire interval, rather than being confined to the first
area penetrated by the acid. With the damage removed
from the perforations and formation, the well is made
more productive and exhibits lower pressure drop across
the producing zone for a longer period of time in the
well’s producing life.
Halliburton has recently developed a crosslinkable HEC
gel that works particularly well with acid-prepack treatments. The gel’s crosslinking is broken when it contacts
low-pH fluids such as acid, allowing a high degree of
fluid leakoff and thus a better external pack. While fluidloss control of the crosslinked gel is excellent, the fluid
leakoff rate of the newly developed gel, once crosslinking is
broken, equals that of a sheared and filtered hydroxyethyl
cellulose (HEC) fluid. Combining the new linear gel with
the acid-prepack treatment yields higher productivity
with a high degree of sand control, because perforations
are first opened and cleaned of LCM, allowing for a
better gravel pack.
Cased Hole Screen/Annulus
Gravel-Pack Systems
Various types of gravel packing systems that provide
screened sections of the completion-equipment string for
gravel retention and fluid entry are available. The gravelpack medium is delivered downhole in many different
ways to provide compatibility with the formation type
being treated. The following discussion focuses on the
many gravel-packing systems available and their
application to unique well situations.
Gravel-Pack Research
Gravel-pack studies were performed by Halliburton in
cooperation with Clausthal University in northern
Germany. The model used for tests simulated Berlin gas
storage wells that were to be gravel packed. The model
was 39 feet long and was cased with 8-5/8-inch plexiglass.
Inside the casing, a 3-1/2-inch gravel-pack screen was
positioned. Simulations were based on three different
permeability profiles:
• 1000-md top zone, 400-md middle zone,
and 200-md bottom zone
• 400-md top zone, 1000-md middle zone,
and 200-md bottom zone
• 200-md top zone, 400-md middle zone,
and 1000-md bottom zone
Conclusions showed water alone as a carrier fluid with
1- to 2-lb/gal sand concentration gave unsatisfactory test
results. Best results were obtained by using a 20-lb/Mgal
gel with 1-lb/gal sand concentration. This was followed by
pumping a stage of brine to help flush any sand buildups
in the annulus and prevent premature bridging. The
slurry and brine stages were alternated.
Halliburton recommends that each sand control completion have a careful analysis done, based on the unique
characteristics of the well. Only then can a packing
procedure, stimulation procedure, or a combination of these
be performed with a high degree of confidence and success.
Slurry Packs
Slurry packs carry sand concentrations downhole, into the
perforations and into fractures, if a stimulation is being
performed. Viscous gel carrier fluids are used to transport
sand concentrations of 4 to 15 lb/gal. The main advantages
to this type of system are that a minimum amount of
water is used to pump the slurry and the pumping rate
can be slowed so that pack sand and formation sand
intermixing is minimal. Disadvantages with slurry packs
can include voids that form in the annulus pack and
incomplete perforation packing, which are caused by the
low leakoff rates and the sparing amounts of water used
in this system.
Water Packs
The water-pack system uses water as a carrier fluid for
gravel-pack sand. In recent years, water packs have become
a popular alternative to gravel-packing methods that use
polymers that can possibly damage formation permeability. Water packs can also help form very tightly packed
annular packs. One disadvantage of water packs is their
high leakoff rate in high-permeability zones, which can
cause bridging in the screen/casing annulus. Bridging in
the screen/casing annulus can cause a premature
screenout of the treatment.
Annular fluid velocity is the key to success with water
packing. The returns should have a minimum flow rate
of 1 to 2 bbl/min. Flow rates lower than 1 to 2 bbl/min
cannot wash sand-node buildup from the annulus.
High-Rate Water Packs
High-rate water packs were developed to overcome the
high leakoff problems encountered with standard water
packs in high-permeability formations. The more
effective high-rate water packs are usually preceded by an
acid prepack. Also, far more sand (up to 700 lb/ft of
perforations) is placed by the more successful high-rate
water packs since the formation parting pressure is
exceeded. Other successful high-rate water pack treatments have been reported from geopressured reservoirs
where very little differential between static formation
pressure and formation parting pressure have existed.
Although the water pack name indicates that only water is
used for proppant transport, frequently a lightly gelled
slurry (25-lb HEC/Mgal) is pumped. The danger that zonal
isolation may be compromised exists with high-rate water
packs, just as it does with FracPac Completion Services.
Tracer log data from some wells that have been waterpacked
indicate that incomplete entry of the tracer over the
entire interval height has occurred, packing only the
high-permeability area of the desired zone. Therefore,
only wells with sands that are sufficient to resist fracture
height growth are candidates for high-rate water packing.
31
FRACPAC COMPLETION SERVICES
Proppant sizes equivalent to those used in gravel packing
are generally the best selection for high-rate water packs
whereas proppant sizing for FracPac treatments emphasizes
fracture conductivity. Pumping rate is determined based
on the length of the zone to be packed. The returns rate
is restricted so that all but 2 bbl/min are forced into the
perforations. A minimum leakoff rate of 5 bbl/min is
recommended, even on short intervals, to ensure that the
fluid has enough velocity to part the formation and
transport the proppant efficiently.
Recommended Improvements to
Gravel Packing Procedures
Several changes in the way that Halliburton prepares to
pump a gravel-pack treatment have helped attain the
desired results on client wells in the last 2 to 3 years.
These improvements are as follows:
• A more thorough cleaning of the casing was performed
before filtering fluids. The use of scouring pills and
surfactant flushes with suspension aids were added to
the wellbore cleanup sequence to remove drilling mud
and rust from the tubulars.
• A more thorough pickling job was performed, including
the use of acid, gel, and a Halliburton pipe-dope removal
chemical. The dope-removal chemical should be tested
with the specific dope used on the job to ensure that it
is compatible.
• The use of Flo-Pac is preferred over HEC fluids.
Flo-Pac provides good sand suspension, built-in viscosity
breaking, high leakoff, and low damage to the formation.
Slightly viscosified fluid (25-lb/Mgal) is preferred over
the use of water for pumping the annular portions of
gravel packs.
32
Chapter 4
INTRODUCTION
With the FracPac service, Halliburton
hydraulically fractures highly permeable
(>10 md) formations to improve production and provide better sand control.
While the reservoir engineering aspects
of fracturing low-permeability formations
have been widely documented throughout petroleum literature,1 these aspects
have not been extensively studied for
high-permeability situations.
concentrates on two topics: production
improvement and sand control. The
effects of permeability, wellbore damage,
fracture length, fracture conductivity,
and fracture damage are studied. Finally,
conclusions are presented that can serve
as specific guidelines for optimizing
FracPac treatments.
Hydraulic fracturing is usually considered
as a technique for increasing productivity
or establishing production in lowpermeability formations. However,
highly permeable formations that have
formation damage or sand production
tendencies can also benefit from
fracturing. For example, a well that has
reduced permeability in a damaged
zone extending several feet from the
wellbore can be made more productive
by fracturing through this damaged
zone to contact undamaged reservoir.
The fracture provides reservoir fluids
with a highly permeable pathway from
the undamaged reservoir to the wellbore.
The conductivity within the fracture
can be maximized so that the pressure
drop along the fracture itself can be
kept to a minimum. In the case of a
well with sand production tendencies,
a hydraulic fracture decreases the
pressure drop necessary to produce the
well at a given rate and changes the flow
regime around the well such that sand
production is minimized or eliminated.
Thus, the fractured well can be produced
at a rate higher than the unfractured
well’s critical sand production rate.
Numerical simulators can be used to
gain a better understanding of the
effects of various reservoir and fracture
parameters on well performance.
Simulators allow the effects of reservoir
permeability, wellbore damage, fracture
length, fracture conductivity, and
fracture damage to be investigated
quickly and thoroughly. The results
discussed in this chapter were generated
with a single-phase, 3-D numerical
simulator, RTZ.2 RTZ is a finite
difference model incorporating a
cylindrical coordinate system. It was
chosen for its ability to model a radially
composite reservoir containing a vertical
fracture. The damaged zone was modeled
by an inner circular region of reduced
permeability extending some radial
distance from the wellbore. Outside the
inner region was an undamaged region
having native reservoir permeability. A
fracture was extended from the wellbore
to various distances in both the damaged
and undamaged zones. In an actual
well, damage (reduced permeability)
can extend from several inches to several
feet away from the wellbore.3 Two
general types of data were generated
from the simulation runs: productivity
as a function of time, and pressure as a
function of distance from the wellbore.
This chapter details the reservoir
engineering aspects of fracturing highpermeability formations. Specifically, it
Reservoir
Engineering
THE STUDY
33
FRACPAC COMPLETION SERVICES
Table 4.1 — Values Applied in Simulations
Value
Parameter
Initial reservoir pressure, pi
4,000 psi
Effective porosity, e
23%
External radius of wellbore damage, rs
1 and 10 ft
Wellbore radius, rw
0.35 ft
Fracture width, bf
0.5 inches
Total compressibility, c t
25x106 psi-1
Formation compressibility, c f
3x106 psi-1
Fluid viscosity, 1.0 cp
Formation thickness, h
30 ft
Oil formation volume factor, Bo
1.2 RB/STB
External radius of formation, re
1,500 ft (160-acre spacing)
Bottomhole flowing pressure, pwf
2,500 psia (for productivity study)
Surface production rate, q
200, 500, and 800 STB/D (for pressure profile)
Formation permeability, k
0.1, 1.0, 10, 100, 1,000, and 10,000 md
Permeability of wellbore-damaged region, ks
Skin, or wellbore damage, S
Fracture half-length, Lf
Fracture conductivity, kf bf
0.01k, 0.05k, 0.1k, 0.2k, and 0.3k md
0, 4.2, 8, 13.5, 20, 30, 65, 104, and 330
5, 14, 40, 80, and 150 ft
100, 500, 2,000, 4,000, 8,000, and 20,000 md-ft
Distance fracture damage extends into
formation from fracture face, bfs
Permeability of fracture-damaged region, kfs
1 ft
0.001k, 0.005k, 0.01k, 0.05k, 0.1k, 0.2k, and 0.3k md
Note: Base values held constant during sensitivity analysis of other variables appear in boldface.
34
Productivity as a function of time is best represented in two
ways: the first is as cumulative production as a function
of producing time; the second is as production increase as
a function of producing time. Production increase was
calculated by dividing cumulative production for stimulated
conditions by cumulative production for unstimulated
conditions. The productivity data were generated under
the assumption that the well was produced at a constant
bottomhole flowing pressure.
Table 4.1 presents the reservoir, fluid, and fracture
parameters used in the study. The values of these
parameters were chosen to provide a representative
example of a typical well that exhibits the effect of each
parameter studied. Skin factor, S, was calculated using
Hawkins’ Equation4 with the permeability, ks , and outer
radius, rs , of the wellbore-damaged region.
Pressure as a function of distance is best represented by a
pressure profile along a vertical plane in the reservoir as a
function of distance from the wellbore. The pressure
data were generated under the assumption that the well
was operated under constant rate conditions.
In many wells, production can be improved by a variety
of methods, the most common of which are hydraulic
fracturing and acidizing. In low-permeability formations,
hydraulic fracturing can create a more favorable flow
pattern to the wellbore. In effect, the wellbore is extended
along the length of the fracture to allow greater productivity. In high-permeability formations, fracturing is used
Production Improvement
Cumulative Production
Different Amounts of Wellbore Damage
Production Increase Due to Fracturing
106
k=
k=
10
Cumulative Production (STB)
Npstimultated /Npunstimultated
100
S=0
0.1
md
1.0
md
k=1
0 md
k = 100 m
d
k = 1,000 md
1
k = 10,000 md
No Damage, S = 0
rs = 1 ft, ks = 0.20 * k, S = 4.2
rs = 10 ft, ks = 0.20 * k, S = 13.5
rs = 1 ft, ks = 0.05 * k, S = 20
105
104
rs = 10 ft, ks = 0.05 * k, S = 65
rs = 1 ft, ks = 0.01 * k, S = 104
rs = 10 ft, ks = 0.01 * k, S = 330
103
0.01
Note:
0.1
1.0
10
Time (months)
100
k = 100 md
0.01
0.1
1.0
10
Time (months)
100
All curves indicate the resulting production increase when a
fracture with Lf = 150 ft and kfbf = 8,000 md-ft is applied.
Figure 4.1 — Production increases due to fracturing are
higher in low-permeability formations than in highpermeability formations.
Figure 4.2 — As wellbore damage increases, cumulative
production decreases.
Production Increase Due to
Removal of Damage
Effects of Permeability and
Wellbore Damage
Figure 4.1 shows the expected production increase when
a 150-ft fracture with 8,000-md-ft conductivity is applied
in undamaged reservoirs having the referenced formation
permeabilities. The figure shows that production increase
is significant at low permeability; however, as permeability
increases, production increase diminishes. Attempts to
increase production by fracturing undamaged formations
with high permeability (i.e., k > 1 darcy) appear to be
futile. Fracturing has little effect on the conductivity of
undamaged, highly permeable formations, so production
increase is insignificant when such formations are fractured.
When damaged, highly permeable formations are fractured,
results are different. Figures 4.2, 4.3, and 4.4 show the
expected cumulative production and production increase
for a 100-md formation with different amounts of wellbore
damage. Each figure shows that production increase is
significant when the effect of damage near the well, also
known as skin, is eliminated. In Figure 4.3, the damaged
zone is removed (e.g., by acidizing) and is replaced with
100
rs = 10 ft, ks = 0.01 * k, S = 330
Npundamaged /Npdamaged
to eliminate the effect of damage near the well. This is
accomplished by extending the fracture through the
damaged zone to contact the undamaged reservoir. This
fracture provides a highly conductive path for reservoir
fluids to reach the wellbore.
k = 100 md
rs = 1 ft, k
s = 0.01 * k, S =
104
rs = 10 ft, k
s = 0.05 * k, S =
65
10
rs = 1 ft, k =
s 0.05 * k, S = 20
rs = 10 ft, k =
s 0.20 * k, S = 13
.5
rs = 1 ft, ks = 0.20 k,
* S = 4.2
1
0.01
Note:
0.1
1.0
10
Time (months)
100
All curves indicate the resulting production increase when
the damaged region is eliminated.
Figure 4.3 — When wellbore damage is removed, production
increases. The more severe the skin, the more dramatic is the
production increase. Skin values here range from 4.2 to 330.
undamaged formation. The figures show that production
increase is significant when a severely damaged, or high
skin, region is removed. Production increase becomes
insignificant at small skin values, i.e., when the magnitude
or depth of permeability reduction near the well is small
(ks ≥ 0.2k or rs ≤ 1 ft). Note that although acidizing can
remove shallow to moderate damage, it is unlikely that it
can remove deep damage. Deep damage effects are more
likely to be eliminated by fracturing than by acidizing.
35
FRACPAC COMPLETION SERVICES
Cumulative Production
Different Fracture Length
Production Increase Due to Fracturing
Npunstimulated /Npdamaged
100
rs = 10 ft, ks = 0.01 * k, S = 330
rs = 1 ft
,k
rs = 10
ft,
10
s = 0.01
rs = 1 ft
,k
* k, S = 1
04
ks = 0.0
5 * k, S
= 65
s = 0.05
* k, S = 20
rs = 10 ft,
k
s
= 0.20
* k, S = 13.5
rs = 1 ft, k
s = 0.20 * k,
S = 4.2
No Wellbore
damage
1
k = 100 md
0.01
Note:
0.1
1.0
10
Time (months)
100
105
k = 100 md
rs = 10 ft
ks = 0.05 * k
S = 65
kfbf = 8,000 md-ft
No Fracture
Lf = 5 ft
Lf = 15 ft
Lf = 40 ft
Lf = 80 ft
Lf = 150 ft
104
103
0.01
0.1
1.0
10
Time (months)
100
All curves indicate the resulting production increase when a
fracture with Lf = 40 ft and kfbf = 8,000 md-ft is applied.
Figure 4.4 — Extending a hydraulic fracture beyond the
damaged zone increases production by providing a clear path
for wellbore fluids to enter the wellbore. Production increases
are shown for a fracture with half-length 40 ft extending through
damaged zones having radii of 1 ft and 10 ft and having
different degrees of damage.
36
Cumulative Production (STB)
106
Figure 4.5 — Once a fracture has extended slightly past
the damaged zone, increases in fracture length bring
increasingly smaller improvements in cumulative production.
In this example, the damaged-zone radius is 10 ft, and the
largest cumulative production improvement is noted as the
fracture half-length extends from 5 to 15 ft.
Figure 4.4 shows the resulting production increase when a
40-ft fracture with 8,000-md-ft conductivity (equivalent to
a dimensionless fracture conductivity, CfD , of 2) is placed
in the formation having the referenced amount of damage.
The production increases here exceed their damage-removal
counterparts in Figure 4.3. Thus, placement of a fracture
extending beyond the damaged zone in a high-permeability
formation yields a production increase that is at least as
large as the resulting production increase for complete
removal of the damaged region.
When combined, Figures 4.1 through 4.4 yield the following conclusion: In high-permeability formations, fracturing
treatments are expected to yield an insignificant production
improvement when there is little or no wellbore damage.
However, properly designed fracturing treatments are
expected to yield significant production improvement
when moderate to high wellbore damage exists. The
degree of production improvement increases as wellbore
damage increases.
Which treatment, acidizing or fracturing, is better for
stimulating production from a damaged, highly permeable
zone? The answer depends on which treatment can satisfactorily eliminate the effect of wellbore damage at the
least cost. As already noted, acidizing may not provide
the required penetration to remove deep damage. An acid
treatment may also leave spent acid in the formation, thus
creating an additional source of damage. Likewise, a fracture
may be difficult to create because of large fluid leakoff;
however, a properly designed treatment can overcome
this problem. These considerations should be addressed
during the design phase of the stimulation treatment.
Effect of Fracture Half-Length
Figures 4.5 and 4.6 illustrate the effect of fracture halflength on cumulative production and production increase.
The case has been simulated for a damaged formation
(rs = 10 ft, ks = 0.05k, S = 65); therefore, all fracture halflengths indicate an increase in production. The largest
increase occurs between the 5-ft and 15-ft half-length
curves. Note that the fracture for the smaller half-length
(5 ft) remained in the damaged region adjacent to the
well, and the fracture for the larger half-length (15 ft)
propagated out of the region. Thus, a large improvement
in production occurs when the fracture is propagated
beyond the damaged region.
Cumulative Production
Production Increase
Different Fracture Conductivity
Different Fracture Length
Npstimulated /Npdamaged
Lf = 150 ft
Lf = 80 ft
Lf = 40 ft
Lf = 15 ft
10
k = 100 md
rs = 10 ft
ks = 0.05 * k
S = 65
kfbf = 8,000 md-ft
No Damage, No Fracture
Lf = 5 ft
1
Cumulative Production (STB)
106
100
105
k = 100 md
rs = 10 ft, ks = 0.05 * k, S = 65
Lf = 40 ft
kfbf = 20,000 md-ft
No Fracture
kfbf = 100 md-ft
kfbf = 500 md-ft
kfbf = 2,000 md-ft
kfbf = 4,000 md-ft
kfbf = 8,000 md-ft
104
103
0.01
0.1
1.0
10
Time (months)
100
0.01
0.1
1.0
10
Time (months)
100
Figure 4.6 — The gains in production obtained by
extending a fracture well past the damaged zone soon
diminish to those gains obtained by extending the
fracture only slightly past the damaged zone.
Figure 4.7 — Only moderate fracture conductivity is required to
improve cumulative production when a fracture extends past the
damaged zone. Further increases in fracture conductivity bring
increasingly smaller improvements in cumulative production.
Figures 4.5 and 4.6 also indicate that fractures propagated
significantly beyond the external radius of the damaged
region do not yield a significant production improvement
over fractures propagated only slightly beyond the damaged
region. This is evidenced by there being only slight shifts
in the cumulative production curves at fracture half-lengths
exceeding 15 ft. This is also shown by the convergence at
the end of 1 year of all production curves corresponding
to fracture half-lengths of 15 ft or more.
indicate the depth of wellbore damage. If a fracture is
deemed necessary, then permeability, amount of damage,
and depth of damage define the desired length of the
fracture. If low permeability is present throughout the
formation, the objective of the fracture treatment should
be to generate large fracture length. Conversely, if the
formation is generally of high permeability but with nearwellbore damage, the objective should be to fracture
beyond the damaged region.
As stated earlier, in low-permeability formations, fractures
effectively extend the wellbore into the formation. Therefore, extension of the fracture is critical in low-permeability
formations. In the high-permeability formations discussed
here, the fracture is merely a conduit between the well
and the undamaged portion of the formation. This is an
important observation because leakoff may make it
difficult to generate significant length in highpermeability formations.
Since the fracture should be designed to extend beyond
wellbore damage, it is important that high-permeability
wells should be tested prior to fracturing to determine the
extent of the damaged zone. A properly designed prefrac
well test is helpful because it can reveal formation
permeability, skin, and heterogenieties and thus indicate
whether a fracture is necessary. Furthermore, analyzing
transient data with a radially composite model can
Effect of Fracture Conductivity
Figures 4.7 and 4.8 illustrate the effect of fracture
conductivity on cumulative production and production
increase. This case is simulated for a well with significant
wellbore damage (S = 65) and with a fracture that extends
beyond the damaged region. The largest production
increase occurs at somewhat low fracture conductivity
(between 100 md-ft and 2,000 md-ft). When a formation
permeability of 100 md is assumed, dimensionless
conductivity values are 0.025 and 0.5 for conductivities
of 100 md-ft and 2,000 md-ft, respectively. When
damaged-zone permeability is assumed to be 5 md, the
dimensionless fracture conductivies are 0.5 and 10.0 for
conductivities of 100 md-ft and 2,000 md-ft, respectively.
Surprisingly, a larger conductivity is not required to
significantly improve production in damaged, highpermeability formations.
37
FRACPAC COMPLETION SERVICES
Cumulative Production
Different Amounts of Fracture Damage
(rs = 10 ft)
Production Increase
Different Fracture Conductivity
Npstimultated /Npunstimultated
k = 100 md
rs = 10 ft
ks = 0.05 * k
S = 65
Lf = 40 ft
kfbf = 20,000 md-ft
kfbf = 8,000 md-ft
kfbf = 4,000 md-ft
kfbf = 2,000 md-ft
10
No Damage,
No Fracture
kfbf = 500 md-ft
kfbf = 100 md-ft
1
Cumulative Production (STB)
106
100
105
k = 100 md
rs = 10 ft
ks = 0.05 * k
S = 65
Lf = 40 ft
kfbf = 8,000 md-ft
bfs = 1 ft
No Fracture
kfs = 0.001 * k
kfs = 0.005 * k
kfs = 0.010 * k
kfs = 0.050 * k
kfs = 0.200 * k
104
103
0.01
0.1
1.0
10
Time (months)
100
Figure 4.8 — Although the gains in production obtained by
highly conductive fractures soon converge to those obtained
with fractures of more moderate conductivity, fractures that are
initially highly conductive are desired because conductivity tends
to decrease with time.
0.01
0.1
1.0
10
Time (months)
100
Figure 4.10 — Conditions in this figure are the same as
those in Figure 4.9, except that wellbore damage extends
10 ft into the formation and produces a skin of 65. This
reduces the production values compared with those of
the previous figure, but the general production trends
are the same.
Cumulative Production
Different Amounts of Fracture Damage
(rs = 1 ft)
Cumulative Production (STB)
106
105
k = 100 md
rs = 1 ft
ks = 0.05 * k
S = 20
Lf = 40 ft
kfbf = 8,000 md-ft
bfs = 1 ft
No Fracture
kfs = 0.001 * k
kfs = 0.005 * k
kfs = 0.010 * k
kfs = 0.050 * k
kfs = 0.200 * k
104
As stated earlier, in the high-permeability formation
discussed here, the fracture serves as a conduit between the
well and the undamaged portion of the formation. It is
important to generate enough conductivity to make this
conduit effective. Because conductivity will typically decline
during production,5 the stimulation treatment should
generate high initial fracture conductivity so that there
will be adequate conductivity throughout production.
103
0.01
0.1
1.0
10
Time (months)
100
Figure 4.9 — As fracture damage increases, cumulative
production improvement from fracturing decreases. This example
considers various permeability reductions that extend 1 ft into
the formation from the fracture face. Skin from wellbore
damage is assumed to be 20.
38
Effect of Fracture Damage
When a high-permeability formation is fractured,
formation damage around the fracture can be expected
because fluid leakoff is significant. Figures 4.9, 4.10,
4.11, 4.12, and 4.13 indicate the effects of fracture
damage on cumulative production and production
increase for two values of wellbore damage. Figures 4.9
and 4.11 correspond to a skin of 20 extending 1 ft into
the formation; Figures 4.10 and 4.12 correspond to a
skin of 65 extending 10 ft into the formation. The
fracture damage was modeled by a zone of reduced
permeability parallel to the fracture face and extending
1 ft into the formation. As expected, production
improvement decreases with increasing fracture damage;
Production Increase
Production Increase
Different Amounts of Fracture Damage
(rs = 1 ft)
Different Amounts of Fracture Damage
(rs = 10 ft)
100
No Fracture Damage
kfs = 0.200 * k
kfs = 0.050 * k
10
k = 100 md
rs = 1 ft
ks = 0.05 * k
S = 20
Lf = 40 ft
kfbf = 8,000 md-ft
bfs = 1 ft
kfs = 0.010 k
*
kfs = 0.005 * k
Npstimulated /Npdamaged
Npstimulated /Npdamaged
100
kfs = 0.001 * k
1
0.01
0.1
No Fracture Damage
kfs = 0.200 * k
kfs = 0.050 * k
kfs = 0.010 k
*
10
k = 100 md
rs = 10 ft
ks = 0.05 * k
S = 65
Lf = 40 ft
kfbf = 8,000 md-ft
bfs = 1 ft
kfs = 0.005 * k
kfs = 0.001 * k
1
1.0
10
Time (months)
100
Figure 4.11 — The increases in production depicted here
correspond to the cumulative production values of Figure 4.9.
0.01
0.1
1.0
10
Time (months)
100
Figure 4.12 — The increases in production depicted here
correspond to the cumulative production values of Figure 4.10.
Cumulative Production
however, production improvement is still significant even
with severe fracture damage.
Fracture damage must be severe before improved
production is significantly limited. Figure 4.13 shows the
cumulative production at 2 and 12 months for a range of
permeability ratios. The ratios were calculated by
dividing fracture-damage permeability by formation
permeability. The figure shows that reducing
permeability by a factor of 10 makes a small difference
after 2 months of production, but to make a difference
after 1 year, the reduction factor in permeability must be
100 or greater.
The conclusion is that in a high-permeability formation
with wellbore damage, even a highly damaged fracture is
better than no fracture. A significant decrease in
production improvement occurs only when fracture
damage is severe or when fracture damage penetrates far
into the formation. Similar conclusions were reached in
an earlier work dealing with the fracturing of lowpermeability formations.6 Deep damage extending from
the fracture can be avoided by properly designing the
fracture treatment to minimize excessive fluid loss. For
practical purposes, a properly designed and conducted
fracturing treatment should result in no productivity
impairment from fracture-face damage.
Cumulative Production (MSTB)
Different Amounts of Fracture Damage
400
rs = 10 ft, ks = 0.05 * k, S = 65
rs = 1 ft, ks = 0.05 * k, S = 20
tp = 1 Year
300
200
100
tp = 2 Months
k = 100 md
Lf = 40 ft
kfbf = 8,000 md-ft
bfs = 1 ft
0
0.001
0.01
0.1
Permeability Ratio (kfs/k)
1.0
Figure 4.13 — The permeability reduction around a fracture
must be excessive before production is significantly affected. In
fact, for the conditions shown, permeability must be reduced by
a factor more than 100 to seriously affect cumulative production
after 1 year.
39
FRACPAC COMPLETION SERVICES
Reservoir Pressure Distribution
Reservoir Pressure Distribution
Effect of Rate
Effect of Wellbore Damage
4,000
4,000
No Wellbore Damage
q = 200 STB/D
3,200
tp = 3 Months
No Wellbore Damage
No Fracture
3,000
1
10
100
Distance from Center of Well (ft)
1,000
Figure 4.14 — Higher production rates cause greater pressure
drops in the formation and greater potential for sanding.
PRESSURE PROFILE
Sand production is a limiting problem in some high-permeability formations, especially those that are unconsolidated.
Sand production reduces the effectiveness of production
equipment and, if uncontrolled, can eventually become
costly because of damaged equipment. For these reasons,
as well as others, many sand-producing wells must be
completed with a gravel pack. Unfortunately, a gravel
pack can sometimes restrict production much like a region
of wellbore damage; therefore, the full potential of some
gravel-packed wells is not realized.
The magnitude and gradient of the pressure drop created
in the formation during production are critical factors
related to the potential for sand production. Thus, it is
important to examine the pressure profiles of high-permeability formations under various producing conditions.
Effects of Producing Rate and
Wellbore Damage
The producing rate at the well affects the magnitude and
gradient of the pressure drop in the formation during
production. Figure 4.14 shows the effect of producing rate
on pressure drop after 3 months of production. The results
are expected and support intuition: higher rates yield larger
pressure drops and steeper pressure gradients in the reservoir.
It is thus expected that there is an upper limit on the rate
at which a well can be flowed without sand production.
40
2,000
65
2,500
=
3,400
3,000
*k
,S
B/D
0.
05
00 ST
=
q=8
STB/D
,S=8
.3 * k
ks = 0
30
S=
k,
.1 *
=0
ks
ks
q = 500
3,600
3,500
Pressure (psi)
Pressure (psi)
3,800
1,500
tp = 3 Months
q = 500 STB/D
rs = 10 ft
No Fracture
1
10
100
Distance from Center of Well (ft)
1,000
Figure 4.15 — As wellbore damage increases so does
pressure drop in the formation. This heightens the
chances for sand production.
The amount of permeability reduction in the damaged
region also affects the magnitude and gradient of the
pressure drop during production. When a well is
produced at a constant rate, as is the case in Figure 4.15,
the pressure drop will be larger and the pressure gradients
will be steeper through a region with a large permeability
reduction. Under the assumptions that the mechanical
properties of the damaged region remain the same as
those of the undamaged region and that the amount of
damage has little effect on the mechanical properties of
the rock, a well with significant damage in the formation is
more likely to produce sand. Consequently, when wellbore
damage exists, the producing rate should be limited to
control the magnitude and gradient of the pressure drop.
Effect of Fracturing
Placing a fracture in the formation significantly alters the
producing-pressure profile. Figure 4.16 contrasts pressure
profiles for various reservoir conditions and includes
profiles already shown in Figures 4.14 and 4.15. The
bottommost curve corresponds to a damaged, unfractured
formation and shows the largest pressure drop. The next
curve up corresponds to an undamaged, unfractured
formation and indicates a constant pressure change
throughout the reservoir. The topmost two curves were
generated under the assumption that a hydraulic fracture
was propagated in the same formation as was used for the
bottommost curve and that the fracture extended beyond
Reservoir Pressure Distribution
Reservoir Pressure Distribution
Effect of Stimulation
Effect of Fracture Length
(Distribution is in fracture plane.)
Fracture propagated beyond damage*
Fracture propagated beyond damage**
4,000
3,100
2,800
No Damag
3,700
e
2,500
tp = 3 Months
q = 500 STB/D
rs = 10 ft
ks = 0.1 * k
1
10
100
Distance from Center of Well (ft)
1,000
Note: * Lf = 40 ft, kfbf = 8,000 md-ft
Distribution is in fracture plane.
** Lf = 40 ft, kfbf = 8,000 md-ft
Distribution is perpendicular to fracture plane.
Pressure (psi)
3,400
D
am
ag
ed
,U
ns
tim
ul
at
ed
Pressure (psi)
3,700
3,400
3,100
2,800
tp = 3 Months, q = 500 STB/D
rs = 10 ft, ks = 0.1 * k, kfbf = 8,000 md-ft
e
No Damag
D
am
ag
ed
,U
nf
ra
ct
ur
ed
4,000
2,500
Lf = 5 ft
Lf = 15 ft
Lf = 40 ft
Lf = 80 ft
Lf = 150 ft
1
10
100
Distance from Center of Well (ft)
1,000
Figure 4.16 — Fracturing a well can virtually eliminate
the effects of wellbore damage on pressure drop in the
formation.
Figure 4.17 — To significantly reduce the effects of wellbore
damage on pressure drop in the formation, a hydraulic fracture
must extend beyond the damaged zone.
the damaged zone. One of the two curves profiles
pressure along the plane of the fracture; the other profiles
pressure perpendicular to the fracture plane.
damaged zone. Sand production could be very likely in
this case because the pressure drop is significant and
pressure gradients are fairly steep from the tip of the
fracture to the outer limit of the damaged region. All the
remaining fracture pressure profiles correspond to
fractures that extend beyond the damaged zone and show
small pressure drops and shallow pressure gradients.
The most important observation is that the fracture
decreases the pressure drop in the formation relative to both
a damaged and an undamaged wellbore condition. Also,
the pressure gradients throughout the fractured formation
are relatively small, even at the tip of the fracture where
the largest pressure drop is expected. Another important
point is that the pressure profile does not significantly
change as the profiling axis is rotated around the well.
Since the pressure drop in a fractured well is less than the
pressure drop in an unfractured well, the best solution for
limiting sand production appears to be to fracture the formation. In addition, fracturing a damaged well can enable
the production improvements shown in earlier sections.
Effect of Fracture Length
Figure 4.17 shows the effect of fracture length on pressure
drop after producing the well at a constant rate for
3 months. For reference, the figure includes the pressure
profiles from Figure 4.16 for an unfractured well with
and without wellbore damage. In the fracture pressure
profiles, the pressure drop is largest and the gradients are
steepest for the fracture that does not propagate past the
It follows that the possibility of sand production is
minimized when the fracture is propagated beyond the
external radius of the damaged region. Therefore, the
fracture should be extended beyond the damaged region
to obtain optimum production improvement and to
minimize sand production.
Effect of Fracture Conductivity
Figure 4.18 shows the effect of fracture conductivity on
pressure drop after producing the well at a constant rate
for 3 months. Like Figure 4.17, the pressure profiles for
an unfractured well with and without wellbore damage
are included. In the fracture profiles, the pressure drop is
greatest and the pressure gradients are steepest at lower
conductivity. Thus, higher fracture conductivities are
desired to minimize the pressure drop and pressure
gradient within the reservoir during production and
thereby reduce the possibility of sand production.
41
FRACPAC COMPLETION SERVICES
Reservoir Pressure Distribution
Reservoir Pressure Distribution
Effect of Fracture Conductivity
(Distribution is in fracture plane.)
Effect of Fracture Damage
(Distribution is in fracture plane.)
4,000
3,100
2,800
kfbf = 100 md-ft
kfbf = 500 md-ft
kfbf = 2,000 md-ft
kfbf = 4,000 md-ft
kfbf = 8,000 md-ft
kfbf = 20,000 md-ft
No Damage
tp = 3 Months, q = 500 STB/D
rs = 10 ft, ks = 0.1 * k, Lf = 40 ft
kfbf = 8,000 md-ft, bfs = 1 ft
3,400
3,100
2,800
kfs = 0.001 * k
kfs = 0.005 * k
kfs = 0.050 * k
kfs = 0.100 * k
kfs = 0.300 * k
No Fracture Skin
No Damage
2,500
2,500
1
10
100
Distance from Center of Well (ft)
1,000
Figure 4.18 — Higher fracture conductivities result in lower
pressure gradients across the formation and minimize the
tendency for sand production.
Effect of Fracture Damage
Figures 4.19 and 4.20 show the effect of fracture damage
on pressure drop and pressure gradient after producing
the well for 3 months. Specifically, Figure 4.19 shows the
pressure profile along the fracture plane, and Figure 4.20
shows the pressure profile perpendicular to the fracture
plane. As expected, larger fracture damage increases the
pressure drop and pressure gradient. The pressure gradient
is most severe at the tip of the fracture; therefore, the
potential for sand production is greatest at this point. It
follows that the depth and magnitude of the permeability
reduction around a fracture should be minimized for
optimum sand control.
CONCLUSIONS
The following are the conclusions reached from the
numerical simulator study.
• Fracturing undamaged, high-permeability formations is
not expected to improve production significantly.
Therefore, fracturing such formations for the sole
purpose of improving production is not recommended.
• Fracturing damaged, high-permeability formations
should increase production and change the expected
pressure profile in the formation, possibly preventing
sand production. Thus, fracturing is a viable completion
option for high-permeability formations where wellbore
damage or the potential for sand production exists.
42
Pressure (psi)
3,700
3,400
D
am
ag
ed
,U
nf
ra
ct
ur
ed
Pressure (psi)
3,700
tp = 3 Months, q = 500 STB/D
rs = 10 ft, ks = 0.1 * k, Lf = 40 ft
D
am
ag
ed
,U
nf
ra
ct
ur
ed
4,000
1
10
100
Distance from Center of Well (ft)
1,000
Figure 4.19 — A high degree of fracture damage can
cause an extremely high pressure gradient in the fracture
plane near the tip of the fracture.
• Fractures that fail to extend beyond the damaged region
in a high-permeability formation will not improve
production to optimum levels and will not significantly
decrease the potential for sand production. So, when
fracturing a high-permeability formation, the fracture
should be designed to extend beyond the damaged
region. It is unnecessary to generate significant fracture
length beyond the external radius of the damaged region;
however, it is always prudent to include a safety factor
in the fracture design.
• Formation permeability, amount of wellbore damage,
and extent of wellbore damage must be known to
determine the necessity of a fracture and the optimum
length and conductivity of the fracture. Hence, to
properly design a fracture treatment, it is important to
run a prefrac well test to determine permeability and
damage parameters.
• When fracturing a high-permeability formation, a
minimum fracture conductivity is required to improve
production and decrease the pressure drop in the
formation. The study demonstrated that a dimensionless
fracture conductivity greater than 0.5 (based on
formation permeability) is adequate.
• Fracture conductivity may decline during production.
Therefore, to assure that production improvement is
maintained and sand production is minimized over the
life of the well, the initial conductivity should be greater
than the conductivity stated in the previous conclusion.
Reservoir Pressure Distribution
kf s
=
permeability in the fracture-damaged
region, md
ks
=
permeability in the wellbore-damaged
region, md
Lf
=
fracture half-length, ft
Effect of Fracture Damage
(Distribution is perpendicular to fracture plane.)
4,000
3,400
3,100
2,800
D
am
ag
ed
,U
nf
ra
ct
ur
ed
Pressure (psi)
3,700
tp = 3 Months, q = 500 STB/D
rs = 10 ft, ks = 0.1 * k, Lf = 40 ft
kfbf = 8,000 md-ft, bfs = 1 ft
kfs = 0.001 * k
kfs = 0.005 * k
kfs = 0.050 * k
kfs = 0.100 * k
kfs = 0.300 * k
No Fracture Skin
No Damage
2,500
1
10
100
Distance from Center of Well (ft)
1,000
Figure 4.20 — When fracture damage is large, high
pressure gradients can arise across the wellbore-damaged
zone perpendicular to the plane of the fracture.
• Fracture damage limits production improvement and
increases the pressure drop and gradient; however, the
fracture damage must be severe before a pronounced
effect is detected. In particular, permeability damage
in the near-fracture vicinity must be great or damage
must penetrate deep into the formation before there is
a significant decline in production improvement and
a pronounced pressure drop. Proper design of the
fracture treatment can minimize deep damage away
from the fracture.
NOMENCLATURE
bf
=
fracture width, ft
bf s
=
distance fracture damage extends into
formation from fracture face, ft
Bo
=
formation volume factor for oil, RB/STB
cf
=
formation compressibility, psi-1
co
=
oil compressibility, psi-1
ct
=
total compressibility, psi-1
h
=
formation thickness, ft
k
=
formation permeability, md
kf bf =
fracture conductivity, md-ft
Np =
cumulative oil production from beginning of
production, STB
pi
initial reservoir pressure, psia
=
pwf =
flowing bottomhole pressure, psia
q
=
surface production rate, STB/D
re
=
external radius of the formation, ft
rs
=
radius of wellbore-damaged region, ft
rw
=
wellbore radius, ft
S
=
wellbore-damage skin, dimensionless
tp
=
production time, months
=
fluid viscosity, cp
e
=
formation effective porosity, fraction
REFERENCES
1. Gidley, J.L., et al.: Recent Advances in Hydraulic Fracturing,
Monograph Series, SPE, Richardson, Texas (1989) 12.
2. Prasad, R.K., and Coble, L.E.: “Horizontal Well Performance
Simulation,” Paper SPE 21087, Latin American Petroleum
Engineering Conference, Rio De Janeiro, October 14-19, 1990.
3. Krueger, R.F.: “An Overview of Formation Damage and Well
Productivity in Oilfield Operations,” JPT (February 1986) 131152.
4. Hawkins, M. F., Jr.: “A Note on the Skin Effect,” Trans., AIME
(1956) 207, 356-357.
5. McDaniel, B.W., and Parker, M.A.: “Accurate Design of
Fracturing Treatment Requires Conductivity Measurements at
Simulated Reservoir Conditions,” Paper SPE 17541, SPE Rocky
Mountain Regional Meeting, Casper, Wyoming, May 11-13, 1988.
6. Holditch, S.A.: “Factors Affecting Water Blocking and Gas Flow
from Hydraulically Fractured Gas Wells,” JPT (December 1979)
1514-1524.
43
FRACPAC COMPLETION SERVICES
44
Chapter 5
INTRODUCTION
Halliburton’s FracPac Completion
Service involves hydraulically fracturing
high-permeability formations. The goal
of the service is to improve production
from formations with deep, severe
damage and to restore the productivity
of wells with sand production
problems. Well testing can aid in
determining whether a well is a
candidate for FracPac completion and,
if so, can provide some of the
important parameters needed in
designing the completion. Furthermore,
a post-treatment well test can assist in
evaluating the effectiveness of the
treatment and can furnish valuable
information for refining completion
design for future wells in the area.
applied mainly to low-permeability
formations, hydraulic fracturing can also
be beneficial in higher-permeability
formations.
This chapter discusses the use of
well-test data as applied to FracPac
completions, provides a general overview
of well-testing methods and equipment,
and presents a recently derived procedure
for using well-test data for type-curve
analysis in formations with low
dimensionless fracture conductivities.
A theoretical example details the
calculations that are typically
encountered in the analysis, and two
field examples illustrate the application
of the procedure to actual wells.
Higher-permeability formations
(10 md ≤ k ≤ 500 md) can also benefit
from fracture stimulation, especially if
there is deep formation damage around
the wellbore. These are the type of
formations to which FracPac
completions are usually applied. The
effects that wellbore damage, fracture
length, fracture conductivity, and
fracture damage have on production
when this completion method is used
were discussed in the previous chapter.
To obtain the best improvement in
production from a FracPac completion,
a highly conductive fracture that extends
past the region of wellbore damage
should be created.
PERMEABILITY INFLUENCE
ON FRACTURING
EFFECTIVENESS
Fracturing is a widely used stimulation
process for enhancing well productivity.
Formation permeability, k, plays a large
role in how effective a fracturing
treatment can be. Although traditionally
Well
Testing
In low-permeability formations
(k < 10 md), hydraulic fracturing
increases the effective wellbore radius by
changing the flow profile to the well
from radial flow to linear flow. The
linear flow of fluids into a highpermeability channel formed by a
hydraulic fracture reduces the flow
pressure drop, especially in the nearwellbore region. Thus, the drag force
and induced stress on formation
particles decline, preventing formation
fines migration and sand production.
In very high permeability formations
(k > 500 md), productivity increases
slightly with fracturing. In general, as
reservoir permeability increases, the
benefits of creating longer fractures
decreases. In the very high permeability
formations, increasing the fracture
45
FRACPAC COMPLETION SERVICES
length will result in only marginal improvements in
productivity. Thus, long fracture lengths may not be
economically prudent. Acid stimulation may restore the
productivity only if the decline in flow is from shallow
skin damage around the wellbore. Theoretically, though,
hydraulic fracturing will improve productivity more than
matrix acidizing as long as the fracture penetrates past
the damaged zone.
to as a tester valve, is run into the hole on drillpipe or
tubing. The pressure inside the tubing or drillpipe is
isolated by the tester valve and is low compared to the
hydrostatic pressure from the column of fluid in the hole
and the pressure of the reservoir. Once on bottom, the
packer is set, isolating the zone of interest. When the
tester valve is opened, the formation is exposed to the
lower pressure, and formation fluids are allowed to enter
the drillpipe or tubing.
WELL TESTS
When the tester valve is closed, a pressure builds up below
the valve as the formation repressures the area around the
wellbore. Depending on equipment configuration, the
tester valve can be repeatedly opened and closed as
desired to create multiple flowing and shut-in periods.
Information from a properly conducted well test can be
used to simply determine the amounts and types of
produced fluids or to perform sophisticated pressure
transient analysis. Some tests may be considered to be
productivity or deliverability tests that can aid in selecting
well completion methods and in designing artificial lift
systems and production facilities. Other types of well tests
are used to determine formation damage or stimulation
effects related to an individual well or to determine
reservoir characteristics such as permeability, pressure,
volume, and heterogeneity.
Application to FracPac Operations
In particular, a well test may be used to determine whether
production can be improved by a FracPac completion or
by another completion or stimulation method such as sand
control, massive hydraulic fracturing, or matrix, fracture,
or closed-fracture acidizing. If FracPac completion services
are performed, a posttreatment well test may provide
fracture half-length and conductivity, formation
permeability and pressure, and the amount of wellbore
skin removed or fracture skin remaining. Additionally,
the reduction in pressure drop around the fracture and
the wellbore may be calculated to determine whether the
lowered pressure drops are sufficient to suppress or control
sand production. All this posttreatment information serves
to establish the FracPac treatment’s degree of success and
is valuable in further improving the stimulation technique
for application in adjacent wells.
Technique and Equipment
Commercial methods for well testing have been available
since 1926. Over the years, the actual methods employed
in well testing have in essence remained unchanged
even though the equipment employed has become
increasingly complex.
In its most basic form, a bottomhole assembly consisting of
a packer and a surface-operated valve, normally referred
46
In addition to a tester valve and one or more packers, a
typical testing assembly will include safety joints; jars; one
or more tools that permit the string contents to be
circulated; mechanical or electrical devices that record
pressure and temperature; and sometimes samplers.
Offshore and hostile environments may require the use of
additional components such as slip joints and various
safety devices such as subsea trees, lubricator/retainer
valves, safety valves, and circulating/safety valves.
Conventional test tools are adequate for testing many
formations. However, interpretation of highly productive
zones may be difficult because of flow restrictions imposed
by such tools. In these cases, full-opening tools, typically
with a 2.25-inch inside diameter (ID) and a 5.0-inch
outside diameter (OD), can be used to produce the zone
of interest at a higher rate. Such tools also allow various
wireline operations such as production logging or
perforating to be carried out through the toolstring.
These full-opening test strings are also suitable for the
various types of stimulation, especially those involving
proppant. Both conventional and full-opening tools are
available in a range of sizes. As tools with smaller ODs are
used, the flow area through the tool decreases. In the case
of smaller full-opening tools, the tools remain fully open
but have a reduced ID.
There are two general methods of operating test tools. The
first method depends on manipulation (reciprocation and
rotation) of the test string to control the flow of the well.
Conventional tools and a limited selection of full-opening
tools are operated in this fashion. With the second method,
once the packer has been set or the seal assembly is in the
permanent packer, no further string manipulation is
required until the end of the test. The flow of the well is
controlled hydraulically by the application and release of
pressure. The second method is preferred for operations
Isobaric Pressure Transients
for a Hydraulically Fractured Formation
(CfD = 0.1)
CfD = 0.1
pwf = 388 psi
∆p = 168.4 psi
pi = 4,900 psi
q = 200 STB/D
tp = 200 hours
Lf = 50 ft
bf = 0.05 ft
Isobaric Pressure Transients
Flow Streamlines
Figure 5.1 — When fracture conductivity is low, the flow profile around the well is essentially radial,
and flowing bottomhole pressure is relatively low.
from floating vessels or in hostile environments. Testing
in harsh environments may require the modification of
objectives to accommodate the physical limitations of the
testing equipment, well-control equipment, casing, and
mud or hole fluid.
Several factors can influence the mechanical success of a
well test. Particularly important, whether in cased or open
hole, is the condition of the mud or hole fluid. This one
factor has the single greatest impact on the operation of
test tools. Mud in poor condition can prevent the operation
of test tools by either of the two methods and can also
prevent retrieval of the toolstring in some cases. To a
certain extent, the types of elastomers used in the tools is
determined by the mud or hole fluid as well as the temperature and the produced fluid. Other major factors that
affect the success of the test are the condition and profile
of the hole or casing and the condition of the test string.
All of these issues as well as the objectives of the test must
be considered long before the actual testing operation.
Detailed, objective planning that results in written
procedures that are accepted and understood by all
concerned parties leads to a successful testing operation.
Since the nature of well testing, which by intent should
result in the production of hydrocarbons, is inherently
hazardous, safety considerations must always be
paramount in the planning process.
47
FRACPAC COMPLETION SERVICES
Isobaric Pressure Transients
for a Hydraulically Fractured Formation
(CfD = 1.0)
CfD = 1.0
pwf = 2,509 psi
∆p = 168.4 psi
pi = 4,900 psi
q = 200 STB/D
tp = 200 hours
Lf = 50 ft
bf = 0.05 ft
Flow Streamlines
Isobaric Pressure Transients
Figure 5.2 — As fracture conductivity increases, the flow profile around the well becomes increasingly
elliptical, and bottomhole flowing pressure increases.
A MODEL FOR ANALYZING
WELL-TEST DATA
Azari et al.1-3 presented a versatile model for the pressure
transient analysis of hydraulically fractured wells. This
model has the broadest range of physical wellbore, fracture,
and formation parameters available in the petroleum
industry. The solution and the provided type-curves are
even applicable for situations in which the flow in a
hydraulically fractured formation resembles a radial
geometry with a negative skin factor, where pseudoradial
flow prevails in a short period of time. Fractures extending
only a few feet in the formation, high skin on the fracture
48
combined with short fracture half-length, and very low
conductivity fractures are a few examples of the extreme
application of the model with near-radial pressure behavior.
This model can also be applied for well testing of FracPac
completions which generally have low dimensionless
fracture conductivity and short fracture half-length.
Before the analysis model is presented, important concepts
regarding dimensionless fracture conductivity and skin
damage are discussed.
Isobaric Pressure Transients
for a Hydraulically Fractured Formation
(CfD = 10)
CfD = 10
pwf = 2,605 psi
∆p = 168.4 psi
pi = 4,900 psi
q = 200 STB/D
tp = 200 hours
Lf = 50 ft
bf = 0.05 ft
Isobaric Pressure Transients
Flow Streamlines
Figure 5.3 — The increase in flowing bottomhole pressure is much larger between Figures 5.1 and 5.2
than between Figures 5.2 and 5.3, although the factor (10) by which fracture conductivity increases is
the same for each pair of figures.
Dimensionless Fracture Conductivity
Dimensionless fracture conductivity, CfD , is defined by
kf bf
Cf D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.1)
kLf
where kf is fracture permeability, bf is fracture width, and
Lf is fracture half-length. In FracPac completions, the value
of bf is high, while both k and kf are medium and Lf is
short. The combination of these parameters is such that
the value of CfD happens to be on the low side. For
example, in a 100-md formation, a fracture with a halflength of 40 ft and having fracture conductivity ranging
from 100 md-ft to 10,000 md-ft produces a dimensionless fracture conductivity of 0.025 to 2.5.
A hydraulic fracturing treatment that results in a low
dimensionless fracture conductivity should not be assumed
a failure. Prats4 indicated that for a given fracture volume, an
increase in the width results in a short fracture, and the
maximum production rate is obtained when the value of
a certain variable, a, is about 1.25 (this corresponds to
CfD ≈ 1.26). As a matter of fact, the majority of well tests
performed on hydraulically fractured wells reveal CfD values
of 1 to 10. As the dimensionless fracture conductivity
drops below 2, the fracture productivity decreases rapidly,
and the fracture becomes less significant while the pressure
49
FRACPAC COMPLETION SERVICES
Isobaric Pressure Transients
for a Hydraulically Fractured Formation
(CfD = 100)
CfD = 100
pwf = 2,768 psi
∆p = 168.4 psi
pi = 4,900 psi
q = 200 STB/D
tp = 200 hours
Lf = 50 ft
bf = 0.05 ft
Isobaric Pressure Transients
Flow Streamlines
Figure 5.4 — In the subject well, further increases in fracture conductivity above 1 continue to increase
the ellipticity of the flow profile but bring only moderate increases in flowing bottomhole pressure.
distribution approaches radial flow. Prats indicated,
“The pressure distribution for a ≥ 100 (CfD ≤ π/200) is
very nearly the same as that for radial flow.”
Even though the dimensionless fracture conductivity of a
FracPac completion is low, the productivity of the well
increases. There are two reasons for the increase. First, the
fracture extends beyond the damaged zone around the
wellbore, which changes the well’s flow profile from radial
to linear or elliptical. Second, sand production is controlled.
In a hydraulically fractured well, productivity is a function
of fracture conductivity, fracture half-length, and fracture
skin, Sf . For a constant flow rate, wellbore pressure
increases as Sf decreases and as CfD or Lf increases.
50
Figures 5.1 through 5.5 show the flow profiles in a 5-md
formation with a fracture half-length of 50 ft after 200
hours of production for dimensionless fracture conductivities of 0.1 to 1,000. For a constant fracture length, the
flowing bottomhole pressure, pwf , increases with CfD .
The largest pressure increase (from 388 to 2,509 psia)
occurs when the dimensionless fracture conductivity
changes from 0.1 to 1.
Skin Damage
An important factor that can reduce the benefits of
hydraulic fracturing is the introduction of skin damage
on the fracture face. Such damage can be attributed to
Isobaric Pressure Transients
for a Hydraulically Fractured Formation
(CfD = 1,000)
CfD = 1,000
pwf = 2,575 psi
∆p = 168.4 psi
pi = 4,900 psi
q = 200 STB/D
tp = 200 hours
Lf = 50 ft
bf = 0.05 ft
Isobaric Pressure Transients
Flow Streamlines
Figure 5.5 — At high fracture conductivities, there is an increase in the fraction of fluid flowing through
the fracture to the wellbore and a decrease in the fraction flowing directly through the formation to the
wellbore. This causes the flow profile to be elliptical rather than radial.
• Incompatibility of fracturing and formation fluids, the
mixing of which can cause clay swelling in the formation5
• Dispersion of formation fines, with subsequent
bridging effects at pore throats5
• Imbibition processes and relative permeability
alterations resulting from liquid movement and
condensation (more evident in tight gas reservoirs)
• Insufficient cleaning of the formation following a
fracturing job
• Unbroken fracturing gels
• Proppant crushing and embedment
Linear skin damage, Sf , as defined by Equation 5.2,
limits fluid flow to the fracture because the damage
covers an extended area on both faces of and alongside
the fracture. By comparison, radial-flow skin damage, S,
as defined by Equation 5.3, covers a much smaller fluid
cross-sectional area but with a higher flux per unit area.
Radial-flow skin damage is the same as wellbore damage,
which has been discussed earlier.
k
Sf 1
kfs
bfs
. . . . . . . . . . . . . . . . . . . . . . . . . . (5.2)
2Lf
51
FRACPAC COMPLETION SERVICES
Production Increase
Different Amounts of Fracture Damage
Npstimulated /Npdamaged
100
No Fracture Damage, Sf = 0
kfs = 0.200 * k, Sf = 0.157
kfs = 0.050 * k, Sf = 0.746
kfs = 0.010 k, S
*
f = 3.89
10
kfs = 0.005 k, S
*
f = 7.82
k = 100 md
rs = 10 ft
ks = 0.05 * k
S = 65
Lf = 40 ft
kfbf = 8,000 md-ft
CfD = 2
bfs = 1 ft
kfs = 0.001 * k, Sf = 39.23
1
0.01
0.1
1.0
10
Time (months)
100
Figure 5.6 — After fracturing, this well would have a productivity
improvement of about 24 at 0.01 month of production, if there
were no fracture damage. If there were fracture damage that
reduced the surrounding formation permeability by a factor of
100 to depth of 1 ft from the fracture, the productivity
improvement would only be about 11. Such fracture damage
corresponds to a fracture skin of about 3.9.
160-acre spacing (i.e., an effective drainage radius, re , of
1,500 ft) reduces the flow by a factor of 18.6. By
comparison, the linear skin damage that was just mentioned
reduces productivity by a factor of 2.2.
_
kh p pwf r
qo 141.2oBo ln e S0.75 . . . . . . . . . . . . . (5.4)
rw
_
where qo is oil flow rate, h is reservoir thickness, p is
average reservoir pressure, pwf is flowing bottomhole
pressure, o is oil viscosity, and Bo is formation volume
factor for oil.
This comparison shows that in a nonfractured formation,
linear skin damage around a fracture face does not reduce
productivity as much as the radial damage around the
wellbore. This is due to the extended cross-sectional area
for flow in hydraulically fractured formations. Damage
must be severe and must extend deep into the formation
before it can significantly reduce the productivity of a
hydraulically fractured formation.
Analysis Model for Low Dimensionless
Fracture Conductivity
where kfs is permeability in the fracture-damaged zone
and bfs is the depth of the fracture-damaged zone as
measured from the face of the fracture.
k
r
S 1 ln s . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.3)
kfs
rw
where k is permeability in the wellbore-damaged zone, rs
is the outer radius of the wellbore-damaged zone, and rw
is the radius of the wellbore.
For the well presented in Figure 5.6, at 0.01 month of
production, the productivity improvement of about 24
with no fracture damage would drop to about 11 if
permeability were reduced by a factor of 100 to a depth
of 1 ft away from the fracture face. From Equation 5.2,
the value of this linear skin damage is 3.9. Whereas, for a
nonfractured well with a radius of 0.35 ft, Equation 5.3
yields a radial skin damage of 134 for a similar 1 ft of
damage, but with the damage measured around the wellbore
instead of away from the fracture face. According to the
pseudosteady-state equation for radial flow of fluids given
by Equation 5.4, a skin value of 134 in a formation with
52
For high-conductivity fractures, fluid flow in the formation
is essentially perpendicular to the fracture face for a
significant period. As fracture conductivity decreases, fluid
flow in the formation parallel to the fracture plane increases
proportionally to provide the least resistant fluid flux path.
This adds to the complexity of the solution by changing a
one-dimensional flow problem to a two-dimensional flow
problem. The resultant fluid flux is directed toward the
wellbore much like a radial flow pattern but with an
elliptical radius of investigation. The shapes of the elliptical
isobaric pressure transients approach a circular profile
with time. Decreasing the fracture’s conductivity and
half-length and increasing the damage on the fracture
face will expedite this transition.
The well-test data for FracPac stimulations will exhibit an
early-time wellbore-storage period, followed by a transition
period, and finally will display pseudoradial flow. This
behavior is similar to that of unstimulated wells. As the
fracture conductivity and half-length increase, an intermediate transition to bilinear flow will start, but true bilinear
flow will not be formed. This extended transition will
only change the pressure profile by creating a longer
transition from storage-dominated flow to pseudoradial
flow. This behavior is also similar to that found with a
radial flow profile with a higher negative skin. Thus, the
Pressure and Pressure-Dervative Type Curves
Finite-Conductivity, Vertical Fractures With Wellbore Coverage
(No Fracture Skin)
102
pwD
Sf = 0.0
ηfD = 1012
101
10-2 = CfD * hfD
10-1
10-1
100
10-2
102
10-3
w
=
S
103
-1
10
-2
10
-3
10
-4
10
-5
10
10
-6
-7
10
10-4
p‘wD * tfD
101
fD
pwD and p‘wD * tfD
100
10-5
10-12
10-9
10-6
10-3
100
103
tfD
Figure 5.7 — These pressure and pressure-derivative type-curves apply to vertical fractures with zero
fracture skin and account for wellbore-storage effects. Note that as wellbore-storage effects increase,
the effects of fracture conductivity decrease.
near-radial pressure responses of a FracPac well could lead
the operator to doubt the existence of a propped
hydraulic fracture.
Figure 5.7 shows the pressure and pressure-derivative
type-curves that account for the influence of both wellbore
storage and fracture conductivity with zero fracture skin.
These type-curves show that the influence of fracture
conductivity diminishes as the value of dimensionless
wellbore storage, SwfD , increases. Since SwfD increases
when Lf decreases, it follows that the creation of a highconductivity fracture is not warranted when fracture halflength is short. The separation between the curves having
different conductivity values increases as the dimensionless wellbore storage decreases (Lf increases) down to 10-4
and stays constant thereafter. Therefore, the fracture halflength should be designed to be long enough to gain the
maximum benefit of a high-conductivity fracture. These
results and observations agree with the published4, 6, 7
productivity increase curves.
Two regions in Figure 5.7 have radial flow behavior. The
first region is located in the rightmost area of the diagram
and represents the short fracture-half-length scenario.
When fracture half-length is short, regardless of the value
of fracture conductivity, a pseudoradial flow profile forms
as wellbore storage dies out. The second region that
represents all the low dimensionless fracture conductivity
situations is located at the top of Figure 5.7. For these
low CfD cases, pseudoradial flow forms even before the
pressure transients reach the tip of fracture.
Cinco-Ley8 showed that flow near the tip of the fracture is
negligible for the low-conductivity fractures, and radial flow
prevails beyond a critical fracture half-length. Azari et al.1
stated that as the dimensionless fracture conductivity
decreases below 0.1, the pressure drop in the fracture
increases more rapidly, causing the transients to move
progressively faster in the formation and slower in the
fracture. Thus, as the dimensionless fracture conductivity
gets lower, the elliptical pressure transients gradually
become circular.
When the dimensionless fracture conductivity is below 0.1,
the shapes of the isobaric pressure transients are so nearly
circular that a radial flow pattern prevails in the formation
even before the isobaric pressure transients reach the tip
of the fracture. Thus, the duration of the bilinear flow
53
FRACPAC COMPLETION SERVICES
Pressure and Pressure-Dervative Type Curves
Finite-Conductivity, Vertical Fractures With Wellbore Storage
(Fracture Skin Present)
100
pwD
2.5 = Sf
CfD * hfD = 1
ηfD = 1012
101
10-1
10-2
10-1
100
fD
p‘wD * tfD
-1
10
-3
10
10
10
-5
=
S
w
10-2
-7
pwD and p‘wD * tfD
101
10-3
10-10
10-7
10-4
tfD
10-1
102
Figure 5.8 — The pressure and pressure-derivative type-curves displayed here apply to vertical fractures
and account for fracture skin and wellbore-storage effects. When there is no fracture damage and
wellbore storage is low, early flow (unit slope) is followed by bilinear flow (quarter slope), linear flow
(half slope), and pseudoradial flow. Increases in wellbore storage decrease the duration of bilinear flow.
As fracture skin increases, the period of wellbore storage increases, and there is a quicker change to
pseudoradial flow.
period decreases with the decrease in dimensionless fracture
conductivity and completely disappears when dimensionless fracture conductivity is below 0.05. Since linear flow
in the formation does not develop for the low-conductivity
fractures, the end of the bilinear flow also corresponds to
the start of the transition to pseudoradial flow. Decreasing
the dimensionless fracture conductivity reduces the duration
of the bilinear flow to a point that bilinear flow ends at
such early times that it may be concealed by wellborestorage effects. Therefore, regardless of the size of the
fracture half-length, the transient pressure profile for low
dimensionless conductivity fractures exhibits near-radial
flow behavior following the end of wellbore-storage effects.
Figure 5.8 shows that the increase of linear fracture skin will
cause the pressure profile of hydraulically fractured wells to
resemble radial flow behavior. Shorter fracture half-length
(corresponding to higher Lf -based dimensionless wellborestorage coefficient, SwfD ) and lower dimensionless
fracture conductivity serve to enhance this resemblance.
In hydraulically fractured formations, pseudoradial flow
develops when the transients in the form of isobaric ellipses
propagate into the formation away from the tip of the
fracture and approach a circular shape. In the analytical
54
solution of Azari et al., pseudoradial flow is asymptotically
tied to the trilinear transform in such a way that the
pressure drop never exceeds an equivalent radial flow.1, 2 As
long as the dimensionless fracture conductivity is above 2,
the onset of pseudoradial flow occurs when dimensionless
time based on fracture length, tf D , is 1.3. Pseudoradial
flow starts progressively earlier for fracture conductivities
below 2 and also with the increase in linear fracture skin
combined with short fracture half-length1 since the transition for such cases is independent of fracture half-length.
The pressure response of a fractured well under
pseudoradial flow is similar to the response of a radial
flow geometry with either an enlarged (apparent)
wellbore radius, rwa , or an improvement in near-wellbore
permeability, yielding an apparent negative radial flow
pseudoskin, S′. The following equations represent the
semilog straight-line behavior of the pseudoradial flow:
1
PwD (ln twD 2S′0.80908) . . . . . . . . . . . . . . . . . (5.5)
2
where pwD is dimensionless pressure and twD is
dimensionless time based on wellbore radius.
rwa rweS ′ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.6a)
Flow-Efficiency Control Parameters
for a Hydraulically Fractured Well
or, solving for S′,
100
rw
S ′ln . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.6b)
rwa
Combining Equations 5.5 and 5.6b yields
10-2
1
PwD (ln twD 2Sc 0.80908) . . . . . . . . . . . . . . . . (5.8)
2
where tfD is dimensionless time based on Lf , and Sc is an
equivalent radial flow pseudoskin that is a function of
fracture conductivity, linear fracture skin, and fracture
half-length as shown in the following equation.
rwa
e Sc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.9a)
Lf
or, solving for Sc ,
Lf
Sc ln . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.9b)
rwa
=
Sf
ηfD = 1012
1.0
10-4
0.0
1
where twaD is the dimensionless time based on rwa ,
and γ is Euler’s constant (1.78107). Equation 5.7 can
be rearranged to provide Equations 5.8 and 5.9:
0
0.
2.5
rwa / Lf
0.1
1
1
4
PwD (ln twaD 0.80908) ln twaD . . . (5.7)
2
2
10-6
10-8
10-3
10-1
101
103
CfD
Figure 5.9 — Fracture conductivity, fracture length, and fracture
skin control flow efficiency in a hydraulically fractured well. As
fracture conductivity increases, the ratio of apparent wellbore
radius to fracture length ultimately becomes essentially constant
at a value that depends upon fracture skin.
Combining Equations 5.6b and 5.9b results in
Lf
Sc S′ln . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.10)
rw
Figure 5.9 shows the relationship between CfD , Lf , and
Sf , which are the flow-efficiency control parameters in a
hydraulically fractured well. This plot demonstrates that
the rate of increase of rwa /Lf with CfD diminishes to a point
that rwa /Lf is essentially a constant value of 0.5 for zero
linear skin, when CfD is greater than 100π. Therefore, the
pseudoradial flow of an infinite-conductivity fractured well
can be represented with a radial-flow expression, similar
to Equation 5.7, that has an apparent wellbore radius of
one-half the fracture half-length. As noted by Cinco-Ley
et al.9 the solution for such a case is basically the same as
the infinite-conductivity solution of Gringarten et al.10
As the ratio of rwa /Lf decreases below 0.5, the value of rwa
approaches rw , and consequently, S′ approaches zero.
According to Equation 5.5, as the negative value of S′
declines, the appearance of a fractured well under pseudoradial flow approaches the profile of an unstimulated
well. Figure 5.9 indicates that the ratio rwa /Lf decreases
as the fracture conductivity decreases and as skin on the
fracture increases. Thus, greater radial-flow performance
and lower fracture productivity will be achieved when one
moves downward through the series of characteristic curves.
In Figure 5.9, the characteristic curve with dimensionless
conductivity less than 0.1 and without linear fracture skin
can be represented by a straight line of unit slope. The
following equation describes this straight-line portion of
the characteristic curves presented in Figure 5.9:
55
FRACPAC COMPLETION SERVICES
rwa
0.18Cf D
Lf
for Cf D 0.1 . . . . . . . . . . . (5.11)
tf D
1
PwD ln ln Swf De 2Sc0.80908 . . . (5.15)
2
Swf D
or, solving for rwa ,
0.18kf bf
rwa k
for Cf D 0.1 . . . . . . . . . . . (5.12)
Cinco-Ley et al.8 presented a similar relationship for
low-conductivity cases. Equation 5.12 indicates that rwa is
independent of fracture half-length when both fracture
conductivity is very low, and bilinear flow ends and
pseudoradial flow starts before the isobaric pressure
transients reach the tip of the fracture.
When CfD < 2, the fracture half-length investigated prior
to formation of pseudoradial flow is less than the true
fracture half-length. This length, defined as effective
fracture half-length, Lfe , continues to decline with lower
CfD down to about CfD = 0.1, below which the effective
wellbore radius and thus the effective fracture half-length
are both independent of Lf . For a given formation, the
excess fracture half-length created above the effective
fracture half-length will not improve productivity. For
fractures with CfD < 0.1, this concept can be applied to
obtain an effective fracture half-length corresponding to
CfD = 0.1 that is the start of the unit-slope line on the
characteristic curve of Figure 5.9. In other words, a
fracture with CfD < 0.1 behaves the same as a fracture
with CfD = 0.1 but with an effective fracture half-length
that is shorter than the true Lf . Using this assumption in
Equation 5.11 results in an effective fracture half-length
of 55 rwa . This number is very sensitive to the start of the
straight line on the characteristic curve. For instance, if it
is assumed that the straight line starts at CfD = 0.2, the
effective fracture half-length equals 27.8rwa . Cinco-Ley et
al.8 report a value of 35rwa as a critical fracture halflength. Most of the effective fracture half-lengths
calculated for the very low-conductivity fractures fall
between 25rwa and 55rwa .
25rwa Lfe 55rwa . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.13)
A more convenient form of presenting Equations 5.5 and 5.8
results when skin and storage are parameterized together:
twD
1
PwD ln ln CDe2S ′ 0.80908 . . . . . . (5.14)
CD
2
56
where CD is dimensionless wellbore-storage coefficient.
The following equalities can easily be established between
the parameters defined for radial flow and the corresponding fracture flow variables:
tf D
twD
= . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.16)
CD
Swf D
CDe 2S ′ Swf D e 2Sc . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.17)
As long as CfD is about or below 0.1, Equation 5.11 can
be combined with Equation 5.15 to yield the following
relationships:
tf D
1
PwD ln Cf D ln Swf De 3Sc 0.916
2
Swf D
. . . . . . . . . . (5.18)
tf D
Swf D
1
PwD ln ln 2 4.24 . . . . . . . . . (5.19)
2
Swf D
Cf D
tf D
1
PwD ln 2 4.24 . . . . . . . . . . . . . . . . . . . . . (5.20)
2
Cf D
The data for the low-conductivity fractures in which the
pressure profile resembles near-radial flow behavior
were grouped together and presented in Figure 5.10.
The parameterized groups of Equation 5.18 are used in
this type-curve.
It has been observed that there may be multiple matches
in the postfrac analysis of a hydraulically fractured well. A
unique solution can only be obtained if the data includes
both the well storage and pseudoradial flow responses, or
they contain at least those measurements made after the
transient responses from the tip of the fracture began to
affect wellbore pressures. If data include storage effects,
and the permeability is known from a prefrac pressure
test, multiple solutions can be prevented because the
y-axis match is predetermined. For FracPac stimulations,
pseudoradial flow prevails rather quickly, allowing for a
unique match of the data with the models based on either
Figure 5.7 or Figure 5.10.
Pressure and Pressure-Derivative Type Curves
Low-Conductivity Hydraulic Fractures
101
3S
-2
p‘wD * tfD
2
0
x1
5
3 6
0
10 x 1
4
3 5
0
10 x 1
3
3 4
0
10 x 1
3 3
10
10
6
pwD
3
10-1
2
x
100
*
Sw
30
10
pwD and p‘wD * tfD
fD
=
c
e
10
10-2
10-1
100
101
102
103
(tfD /SwfD) * CfD
Figure 5.10 — These type-curves were developed to account for the pseudoradial flow behavior that
occurs in wells with low-conductivity hydraulic fractures.
ANALYSIS EXAMPLES
A Theoretical Example
The technique presented here for the evaluation and
analysis of short fractures induced in high-permeability
formations is unique in the petroleum industry. The model
has more fracture and formation parameters than any
other available model in the industry.1-3 The solutions are
accurate over extreme ranges of the parameters and are
beyond the limits of accuracy of other available models.
The ranges shown for wellbore storage, conductivity,
skin values, and time presented in the type-curves of
Figures 5.7, 5.8, and 5.10 are not available anywhere else.
Halliburton was the first to present solutions and typecurves for the dimensionless fracture conductivities below
0.1, and still there is no other solution available below 0.01.
This example illustrates the pressure transient analysis for
a FracPac stimulation. The induced fracture for a highpermeability reservoir may not effectively bypass all of the
skin damage around the wellbore, leaving behind a small
positive or negative apparent radial-flow pseudoskin value.
The following examples demonstrate the application of
the type-curves shown in Figures 5.7 and 5.10 to the
analysis of low-conductivity fractured wells in which the
pressure responses resemble near-radial flow profiles.
An analytical design model was employed to generate 48
hours of theoretical pressure buildup for a fractured well
in an undersaturated oil reservoir. The design model
generates pressure versus time values based on the
appropriate pwD and tD functional relationship for a
particular reservoir system.
Table 5.1 displays rock and fluid data. Table 5.2 gives the
pressures, rate schedule, cumulative times, and plotting
function11, 12 values used in the analysis. Figure 5.11
presents the log-log type-curve match, and Table 5.3
shows analysis results. In this example, the presence of a
short fracture half-length has prevented the development
57
FRACPAC COMPLETION SERVICES
Table 5.1 — Basic Reservoir Properties for Theoretical Example
Parameter
Value
System
Oil
Dynamic Pay Thickness, ft
5
Initial Pressure, psia
6,014.65
Oil Viscosity, cp
0.45
Reservoir Temperature, °F
150
System Compressibility, 1/MMpsi
15
Effective Porosity
7%
Oil Compressibility, 1/MMpsi
12
Oil Formation Volume Factor, RB/STB
1.0
Wellbore Radius, ft
0.25
Oil Rate, STB/D
200
Producing Time, hours
24
Table 5.2 — Time, Pressure, and Plotting Function Values for Theoretical Example
Pt.
Time,
Pressure,
Pressure,
Equivalent
psia
Time, hours
psi
No. hours
Pt.
Time,
Pressure,
Pressure,
Equivalent
psia
Time, hours
psi
No. hours
1
2
3
4
5
24.0
24.0
24.0
24.0
24.0
4,180.36
4,210.78
4,240.06
4,268.39
4,295.88
2.400E+01
9.996E-03
1.998E-02
2.996E-02
3.993E-02
*
3.042E+01
5.970E+01
8.803E+01
1.155E+02
26
27
28
29
30
28.0
29.0
30.0
32.0
33.0
5,729.87
5,764.18
5,789.38
5,824.97
5,838.27
3.429E+00
4.138E+00
4.800E+00
6.000E+00
6.545E+00
1.550E+03
1.584E+03
1.609E+03
1.645E+03
1.658E+03
6
7
8
9
10
24.1
24.1
24.1
24.1
24.1
4,322.58
4,348.55
4,398.42
4,445.73
4,490.61
4.990E-02
5.985E-02
7.973E-02
9.959E-02
1.194E-01
11.422E+02
1.682E+02
2.181E+02
2.654E+02
3.103E+02
31
32
33
34
35
34.0
36.0
38.0
40.0
42.0
5,849.60
5,867.95
5,881.97
5,893.59
5,903.32
7.059E+00
8.000E+00
8.842E+00
9.600E+00
1.029E+01
1.669E+03
1.688E+03
1.702E+03
1.713E+03
1.723E+03
11
12
13
14
15
24.1
24.2
24.2
24.2
24.3
4,532.26
4,572.12
4,610.20
4,646.50
4,730.45
1.392E-01
1.589E-01
1.787E-01
1.983E-01
2.474E-01
3.519E+02
3.918E+02
4.298E+02
4.661E+02
5.501E+02
36
37
38
39
40
44.0
46.0
48.0
50.0
52.0
5,911.50
5,918.52
5,924.61
5,929.95
5,934.68
1.091E+01
1.148E+01
1.200E+01
1.248E+01
1.292E+01
1.731E+03
1.738E+03
1.744E+03
1.750E+03
1.754E+03
16
17
18
19
20
24.3
24.4
24.5
24.6
24.8
4,805.79
4,934.96
5,040.98
5,128.83
5,264.03
2.963E-01
3.934E-01
4.898E-01
5.854E-01
7.742E-01
6.254E+02
7.546E+02
8.606E+02
9.485E+02
1.084E+03
41
42
43
44
45
54.0
56.0
58.0
60.0
62.0
5,938.89
5,942.68
5,946.09
5,949.19
5,952.02
1.333E+01
1.371E+01
1.407E+01
1.440E+01
1.471E+01
1.759E+03
1.762E+03
1.766E+03
1.769E+03
1.772E+03
21
22
23
24
25
25.0
25.5
26.0
26.5
27.0
5,361.34
5,504.16
5,586.44
5,640.13
5,678.29
9.600E-01
1.412E+00
1.846E+00
2.264E+00
2.667E+00
1.181E+03
1.324E+03
1.406E+03
1.460E+03
1.498E+03
46
47
48
49
50
64.0
66.0
68.0
70.0
72.0
5,954.61
5,956.99
5,959.19
5,961.22
5,963.11
1.500E+01
1.527E+01
1.553E+01
1.577E+01
1.600E+01
1.774E+03
1.777E+03
1.779E+03
1.781E+03
1.783E+03
Table 5.3 — Log-Log Type-Curve Analysis Results for Theoretical Example
Parameter
Type-Curve Match, pw D
1
Oil Permeability, md
10.17
Type-Curve Match, (tf D /Swf D ) * Cf D
0.1
Fracture Half-Length, ft
48.6
Data Plot p, psi
250
Fracture Conductivity, dimensionless
0.048
Data Plot te′ hours
0.168
Fracture Conductivity, md-ft
23.7
Apparent Radial Flow Pseudoskin, S ′
-0.515
Apparent Wellbore Radius, rwa ′ ft
0.418
Swf D
e3Sc
Wellbore Storage Constant, SwfD ′ dimensionless
58
Value
3x
105
0.1935
Type-Curve Matching
Log-Log Type-Curve Match
Theoretical Example
104
∆p and d(∆p)/d[In(∆te)] (psi)
of any commonly recognizable fracture flow regime. The
data exhibit well-storage effects at early time followed by
transition to pseudoradial flow. The type-curve match
was performed with an on-screen type-curve matching
program that draws a series of analytical curves on the
screen and allows the user to “drag” the actual well-test
data until a match is achieved. The software
automatically calculates formation and fracture
parameters from the selected match. The manual
calculations to obtain the analysis results for the typecurves illustrated in Figure 5.10 follow. The type-curve
analysis technique for Figure 5.7 follows the basic typecurve matching mechanics presented in Earlougher’s
Advances in Well Test Analysis.13
CfD = 0.048
SwfD = 0.1935
SwfD * e3Sc = 3 * 105
S‘ = -0.515
Lf = 48.6 ft
103
D
6
102
∆p
c
3S
10
=
S wf
*
e
3 * 105
105
The following match data were recorded from the onscreen type-curve matching program:
d(∆p)/d[In(∆te)]
101
• type-curve: pwD = 1
10-1
• data plot: ∆p = 250 psi
100
∆te (hours)
101
102
Figure 5.11 — A theoretical problem involving a lowconductivity hydraulic fracture was solved by on-screen typecurve matching in which the type-curves of Figure 5.10 were
used. The results are shown here.
• type-curve: (tfD/SwfD)CfD = 0.1
• data plot: ∆te = 0.168 hour
• SwfDe3Sc = 3105
Type-Curve Solution
1. Obtain permeability from the dimensionless pressure
equation:
141.26qo Bo o pwD
ko h p
for oil . . . . . . . . (5.21a)
where ∆p is pressure difference.
1,424qgTpwD
kg hDm(p)
for gas . . . . . . . . . (5.21b)
2. Calculate wellbore-storage coefficient, Cw , from the
unit-slope line:
1
Cw qoBo t/
punit slope for oil . . . . . . . . (5.22a)
24
1
Cw qg Bg t/
punit slope for gas . . . . . . . . (5.22b)
24
where Bg is formation volume factor for gas.
where kg is formation permeability to gas, qg is gas flow
rate, T is reservoir temperature, D is turbulent flow
coefficient, and m(p) is pseudopressure.
ko = [41.26(200 STB/D)(1 RB/STB)(0.45cp)(1)]/
Cw = [(1/24)(200 STB/D)(1 RB/STB)][(0.1 hour)/
(312.4 psi)]
Cw = 0.0027 bbl/psi
[(250)(5 ft)]
ko = 10.17 md
59
FRACPAC COMPLETION SERVICES
Log-Log Type-Curve Match
∆m(p) and d[∆m(p)]/d[In(∆te)] (psi2/cp)
Field Example 1
(Gas Well)
109
108
CfD = 0.072
SwfD = 0.173
SwfD * e3Sc = 8 * 104
S‘ = -0.126
Lf = 22.2 ft
rwa /Lf = (0.18)(0.048) = 0.0086
6. Use Equation 5.9b to evaluate Sc :
∆m(p)
c
3S
fD
107
5
3*
10
=
*
e
Sw
8 * 104
3 * 104
106
10-2
5. Apply Equation 5.11 to calculate rwa /Lf since the value
of CfD is less than 0.1. Otherwise, Figure 5.9 would be
used.
d[∆m(p)]/d[In(∆te)]
10-1
100
∆te (hours)
101
Figure 5.12 — Type-curve analysis was performed on postfrac
pressure-buildup data from a well that had proved difficult to
bring onto production. The on-screen analysis used the typecurves of Figure 5.10 to generate these results.
Sc = ln(1/0.0086) = 4.75
7. Obtain SwfD from the following equation, where M
indicates that the value of the expression is obtained from
curve matching:
/
Swf D Swf D e3ScM e3Sc . . . . . . . . . . . . . . . . . . . . . . . . . (5.25)
SwfD = 3x105/e3x4.75 = 0.1935
8. Calculate the apparent radial-flow pseudoskin using
Equation 5.17:
1
S′ = ln Swf D e3Sc CD eSc . . . . . . . . . . . . . . . . . . . . . (5.26)
2
/
3. Obtain dimensionless wellbore storage from the
following relationship:
5.615Cw
................................................(5.23)
CD 2ct hrw2
where φ is formation porosity and ct is the total
compressibility of the formation matrix.
CD = [5.615(0.0027 bbl/psi)]/[2π(0.07)(1510-6 psi-1)
(5 ft)(0.25 ft)2]
CD = 7,266
4. The x-axis of the type-curve in Figure 5.10 can be
reduced to the following relationship:
/
0.0003kht
S′ = 1/2 ln (3x105 / 7,266 e4.75) = -0.515
9. Use Equation 5.6a to calculate apparent wellbore
radius:
rwa = (0.25 ft)e-(-0.515) = 0.418 ft
10. Using rwa from Step 9 and rwa/Lf from Step 5,
calculate Lf from the following equation:
/ /
Lf rwa rwa Lf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.27)
Lf = (0.418 ft)/(0.0086)
Lf = 48.6 ft
Cf D . . . . . . . . . . . (5.24)
tf D Swf D Cf D C
11. Use k, CfD , and Lf calculated from Steps 1, 4, and 10,
respectively, to determine fracture conductivity:
Use Equation 5.24 to calculate CfD from the x-axis match
of the type-curve and the data plot:
kf bf Cf D kLf . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5.28)
w
CfD = [(0.1)(0.45 cp)(0.0027 bbl/psi)]/[(0.0003)
(10.17 md)(5 ft)(0.168)]
CfD = 0.048
kf bf = (0.048)(10.17 md)(48.6 ft) = 23.7 md-ft
12. Estimate the effective fracture half-length using
Equation 5.13:
Lfe = 10 ft to 23 ft
60
Table 5.4 — Basic Reservoir Properties for Field Example 1
Parameter
Value
System
Gas
Dynamic Pay Thickness, ft
21
Initial Pressure, psia
2,006
Well Stream Gas Gravity
0.6565
Reservoir Temperature, °F
155
Gas Viscosity, cp
0.017
Effective Porosity
7.6%
System Compressibility, 1/MMpsi
383
Water Saturation
28.0%
Gas Compressibility, 1/MMpsi
528
Gas Formation Volume Factor, RB/Mscf
1.296
Wellbore Radius, ft
0.328
Table 5.5 — Log-Log Type-Curve Analysis Results for Field Example 1
Parameter
Value
Type-Curve Match, pw D
1
Gas Permeability, md
4.47
Type-Curve Match, (tf D /Swf D ) x Cf D
0.1
Fracture Half-Length, ft
22.2
Data Plot m(p), psia2/cp
1.8 x 107
Fracture Conductivity, dimensionless
0.072
Data Plot te′ hours
0.082
Fracture Conductivity, md-ft
7.16
Apparent Radial Flow Pseudoskin, S ′
-0.126
Apparent Wellbore Radius, rwa ′ ft
0.289
Swf D
e3Sc
Wellbore Storage Constant, SwfD ′ dimensionless
8x
104
0.173
Field Example 1
Field Example 2
The operator of this gas well was experiencing difficulty
in bringing the well on production. A prefracture buildup
test was not run on this well because the operator had
problems initiating any significant flow prior to the fracture
treatment. A hydraulic fracturing treatment consisting of
1,429 bbl of gel plus 90,000 lb of 16/30 Ottawa sand was
pumped into the formation. After a 5-hour wait for fracture
closure, the well was flowed back on an 8/64-inch choke.
At the end of the ensuing 136.5-hour flowback period,
800 bbl of fracturing fluid were still unrecovered. The gas
rate had stabilized at 1,928 Mscf/D prior to the initiation
of the 78.5-hour postfracture pressure buildup test. Basic
reservoir data for this system are given in Table 5.4.
Analysis of the postfracture pressure buildup data was
accomplished with the previously mentioned on-screen
type-curve matching software.
A 94-hour pressure buildup test was run on this oil well,
which was producing from a dolomite formation. This
well was acid-fractured earlier in its life, and the reservoir
pressure was below the bubble point at the time of the
test. Rock and fluid data for this case are presented in
Table 5.6.
The type-curve matching results presented in Table 5.5
and Figure 5.12 yielded an effective permeability to gas
of 4.47 md, a fracture half-length of 22.2 ft, and a
fracture conductivity of 7.16 md-ft. The data indicate
wellbore-storage effects at early time, with transition to
pseudoradial flow regime.
The type-curve matching results presented in Table 5.7
and Figure 5.13 were accomplished by using on-screen
type-curve matching software based on Figure 5.7. A
radial-flow type-curve analysis of the data yielded
ko = 3.34 md, S = -4.06, and CD = 9.82102, while the
linear regression of the straight-line semilog data provided
an effective permeability to oil of 3.8 md and a radial
skin factor of -3.79. This example illustrates that the
pressure transient test of a hydraulically fractured well
having a short fracture half-length resembles radial flow
behavior even if fracture conductivity is high.
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FRACPAC COMPLETION SERVICES
Table 5.6 — Basic Reservoir Properties for Field Example 2
Parameter
Value
System
Oil/Gas
Dynamic Pay Thickness, ft
6
Initial Pressure, psia
2,995
API Gravity of Oil, °API
44
Reservoir Temperature, °F
209
Bubble Point GOR, scf/STB
714
Effective Porosity
10%
Bubble Point Pressure, psia
3,000
Water Saturation
35%
Separator Gas Gravity
0.62
Pressure for PVT Properties, psia
2,220
Oil Viscosity, cp
0.365
Oil Formation Volume Factor, RB/STB
1.363
System Compressibility, 1/MMpsi
126
Wellbore Radius, ft
0.328
Oil Compressibility, 1/MMpsi
189
Table 5.7 — Log-Log Type-Curve Analysis Results for Field Example 2
Parameter
Value
Type-Curve Match, pw D
1
Oil Permeability, md
3.96
Type-Curve Match, tf D
10-2
Fracture Half-Length, ft
28.6
Data Plot m(p), psi/cp
7.2 x 102
Fracture Conductivity, dimensionless
50
Fracture Conductivity, md-ft
5,663
10-2
Data Plot te′ hours
3.6 x
Wellbore Storage Constant, SwfD ′ dimensionless
0.14
Fracture/Matrix Diffusivity, dimensionless
1012
Skin on the Fracture, dimensionless
0.01
Apparent Radial Flow Pseudoskin, S ′
-3.75
Fracture Height, dimensionless
1
Apparent Wellbore Radius, rwa ′ ft
13.95
Log-Log Type-Curve Match
∆m(p) and d[∆m(p)]/d[In(∆te)] (psi2/cp)
Field Example 2
(Oil Well)
103
102
CfD ≥ 50
SwfD = 0.14
Sf = 0.01
S‘ = -3.75
ηfd = 1012
Lf = 28.6 ft
NOMENCLATURE
bf = fracture width, ft
∆m(p)
bf s = depth of fracture-damaged zone, as measured
from fracture face, ft
Bg = formation volume factor for gas, RB/Mscf
d[∆m(p)]/d[In(∆te)]
Bo = formation volume factor for oil, RB/STB
101
Cf D = fracture conductivity, dimensionless
10-2
10-1
100
∆te (hours)
101
102
Figure 5.13 — The on-screen type-curve analysis that produced
these results was based on the type-curves of Figure 5.7. The
well had been acid-fractured earlier in its life.
ct = formation matrix total compressibility, psi-1
CD = wellbore-storage coefficient, dimensionless
Cw = wellbore-storage coefficient, bbl/psi
D = turbulent flow coefficient, q-2
h = reservoir thickness, ft
hf D = fracture height, dimensionless
62
k = formation permeability, md
T = reservoir temperature, °R
kf = fracture permeability, md
te = equivalent time, hours
kg = formation permeability relative to gas, md
ko = formation permeability relative to oil, md
ks = permeability of wellbore-damaged zone, md
kf s = permeability of fracture-damaged zone, md
Lf = fracture half-length, ft
p
p dp
, psi / cp
(p)z(p)
2
for gas
p
dp
, psi / cp
(p)B (p)
z = gas compressibility factor, dimensionless
p = pressure difference, psia
= hydraulic diffusivity ratio, dimensionless
po
po
twaD = dimensionless time, based on apparent
wellbore radius
= Euler’s constant, 1.78107
m(p) = pseudopressure
m(p)
tp = producing time, hours
twD = dimensionless time, based on wellbore radius
Lf e = effective fracture half-length, ft
m(p)2
tf D = dimensionless time, based on fracture
half-length
for oil
o
PwD = wellbore pressure, dimensionless
pwf = bottomhole flowing pressure, psia
_
p = surface production rate, STB/D
qg = gas flow rate, Mscf/D
qo = oil flow rate, STB/D
re = effective reservoir drainage radius, ft
rs = external radius of wellbore-damaged region, ft
rw = wellbore radius, ft
rwa = apparent wellbore radius, ft
S = wellbore-damage skin, dimensionless
S′ = apparent radial flow pseudoskin,
dimensionless
Sc = equivalent radial flow pseudoskin, dimensionless
Sf = linear-flow skin damage (fracture-damage
skin), dimensionless
Swf D = wellbore-storage coefficient, dimensionless
o = oil viscosity, cp
= formation porosity, fraction
REFERENCES
1. Azari, M., Wooden, W.O., and Coble, L.E.: “A Complete Set of
Laplace Transforms for Finite-Conductivity Vertical Fractures
Under Bilinear and Trilinear Flows,” Paper SPE 20556, 1990 SPE
Annual Technical Conference and Exhibition, New Orleans,
September 23-26.
2. Azari, M., Wooden, W.O., and Coble, L.E.: “Further Investigation on
the Analytic Solutions for Finite-Conductivity Vertical Fractures,”
Paper SPE 21402, SPE Middle East Oil Technical Conference and
Exhibition, Manama, Bahrain, November 16-19, 1991.
3. Azari, M., et al.: “Performance Prediction for Finite-Conductivity
Vertical Fractures,” Paper SPE 22659, 1991 SPE Annual Technical
Conference and Exhibition, Dallas, October 6-9.
4. Prats, M.: “Effect of Vertical Fracture on Reservoir Behavior–
Incompressible Fluid Case,” SPEJ (June 1961) 105-118.
5. Azari, M.: “Formation Permeability Damage Induced by
Completion Brines,” JPT (April 1990) 486-492.
6. Tinsley, J.M., et al.: “Vertical Fracture Height–Its Effect on Steady
State Production Increase,” JPT (May 1969) 633-638.
7. Soliman, M.Y.: “Modifications to Production Increase Calculations
for a Hydraulically Fractured Well,” JPT (January 1983) 170-172.
8. Cinco-Ley, H., Ramey, H.J., Jr., and Rodriguez, F.: “Behavior of
Wells With Low-Conductivity Vertical Fractures,” Paper SPE
16776, 1987 SPE Annual Technical Conference and Exhibition,
Dallas, September 27-30.
63
FRACPAC COMPLETION SERVICES
9. Cinco-Ley, H., Samaniego, V.F., and Dominguez, A.N.: “Transient
Pressure Behavior for a Well With a Finite-Conductivity Vertical
Fracture,” SPEJ (August 1978) 253-254.
10. Gringarten, A.C., Ramey, H.J., Jr., and Raghavan, R.: “UnsteadyState Pressure Distribution Created by a Well With a Single
Infinite-Conductivity Vertical Fracture,” SPEJ (August 1974)
347-360; Trans., AIME, 257.
11. Agarwal, R.G.: “A New Method to Account for Producing Time
Effects When Drawdown Type-Curves Are Used to Analyze Pressure
Buildup and Other Test Data,” Paper SPE 9829, 1980 SPE Annual
Technical Conference and Exhibition, Dallas, September 21-24.
12. Al-Hussainy, R., Ramey, H.J., and Crawford, P.B.: “The Flow of
Real Gases Through Porous Media,” JPT (May 1966) 624-636;
Trans., AIME, 237.
13. Earlougher, R.C., Jr.: Advances in Well Test Analysis, Monograph
Series, SPE, Dallas (1977) 5, 24-27.
64
Chapter 6
INTRODUCTION
Some of the formation parameters used
in designing a FracPac job can be
obtained from wireline logging
measurements. These parameters
include stress, shale volume, pressure,
and permeability. Necessary data can
be obtained from tools run in open
holes; however, some of the data
cannot be acquired in cased wells.
WIRELINE
MEASUREMENTS
The wireline measurements used in
FracPac design are obtained primarily
from sonic, gamma, density, and formation tester devices. Sonic and density
tools provide the measurements needed
to calculate formation stresses, while
gamma tools are the main instruments
for determining shale volume. Formation
testers give information from which
formation pressure and permeability may
be derived, although these parameters
are often obtained by other means.
Advantages
Sonic, gamma, and density tools move
continuously through the wellbore as
they make their measurements. Measurements are recorded as a function of
depth, typically every 0.25 ft or 0.10 m.
Because of this dense sampling of
formation properties, these measurements are often considered as being
continuous. When dense data such as
this is used in the FracPac simulator and
other programs for designing fracturing
jobs, it allows for improved vertical
resolution of stress variations, thereby
enhancing design results.
Rock mechanical properties such as
Poisson’s ratio, Young’s modulus, shear
modulus, and bulk compressibility are
calculated from wireline measurements
as an intermediate step in determining
formation stress. When rock properties
are derived from acoustic measurements,
they are referred to as dynamic measurements; when derived otherwise, they
are referred to as static measurements.
Thus, log-derived rock properties are
dynamic properties. Rock properties
obtained from cores can be dynamic or
static, depending on whether the
measurements were obtained with
acoustic devices. Since there can be a
considerable difference between
corresponding dynamic and static
properties, it is important to distinguish
which type is under consideration in
discussions and calculations.
Design
Logging
When rock properties are determined
from measurements made with the rock
in its natural environment, such as with
logging measurements, the properties are
referred to as in-situ properties. When
the properties are determined from
measurements made with the rock out
of its natural environment, such as with
core measurements, the properties are
referred to as ex-situ properties. As with
dynamic and static properties, there can
be a marked difference between in-situ
and ex-situ values. The coring process
itself stresses the sample, possibly
affecting the sample’s mechanical
properties. This is especially possible in
unconsolidated rock, where often a core
cannot be retrieved. Furthermore, shale
dehydration can affect measurements on
shaly cores since the mechanical properties of shales are directly related to their
water content. When the rock properties
are finally measured at the surface, the
65
FRACPAC COMPLETION SERVICES
conditions on the core are often quite different from those
in the formation from which the core was retrieved.
Determining rock properties from logging data eliminates
the effects of core damage and of pressure and fluid changes
that occur during core retrieval. To ensure that the dynamic
rock properties and the resulting stress field components
that are calculated from logging measurements correlate
with the actual values of these parameters, the calculated
values should be calibrated using microfrac data.
Sonic Measurements
Acoustic energy propagates through matter as waves, the
most commonly known being compressional and shear
waves. Acoustic slowness is the time required for an acoustic
wave to travel a specified distance through a material, usually
1 ft or 1 m. Slowness is usually expressed in microseconds
per foot (s/ft) or microseconds per meter (s/m). Using
acoustic sources and sensors, wireline sonic tools measure
a formation’s compressional and shear slowness, tc and
ts , respectively. These are the two acoustic parameters
needed in determining formation stresses.
Two types of sonic tools can be used to measure tc and
ts , depending on whether the formation is slow. A formation is slow when ts > t f , where t f is borehole fluid
slowness. (The nominal value of t f for water is 189 s/ft.)
Full waveform sonic tools, such as Halliburton’s Full Wave
Sonic, use monopole acoustic transmitters and receivers to
generate and sense compressional and shear waves that
travel along the borehole wall. The tools are thus able to
measure tc and ts . When the formation is slow, laws of
physics dictate that monopole tools cannot give rise to shear
waves along the borehole wall and so cannot measure ts .
In slow formations, a dipole sonic tool, such as Halliburton’s
Low Frequency Dipole, is run. A dipole acoustic transmitter
generates flexural waves that travel along the borehole wall
and are sensed by dipole receivers to measure flexural
slowness. At low frequencies, flexural waves travel with
the same slowness as shear waves; thus, measuring flexural
slowness is tantamount to measuring shear slowness.
Dipole tools also contain monopole acoustic transmitters
and receivers to enable compressional slowness to be
measured. Figure 6.1 presents a dipole sonic log.
Density Measurements
Formation density, also known as formation bulk density
and designated b ′ is the combined mass per unit volume
66
of all materials in the formation, whether solid, liquid, or
gas. Wireline density tools contain a chemical source of
gamma rays and two gamma ray detectors. Gamma rays
are emitted by the source into the formation, with some
of the gamma rays being scattered back to the tool and
sensed by the detectors. The density measurement is based
on the assumption that as formation density increases, the
number of gamma rays scattered back to the tool decreases.
The measured bulk density is used to determine overburden
pressure, po. Bulk density and overburden pressure are
used with tc and ts in computing formation stresses.
Either traditional or spectral density tools can be used in
open holes to measure b . Traditional density tools measure
gamma radiation returning to the tool in a single broad
energy range. By contrast, spectral density tools measure
the amounts of gamma radiation returning to the tool in
several specific energy ranges. The spectral tools can
provide a more accurate b measurement and also furnish a
measurement of formation photoelectric factor useful in
identifying formation lithology.
Gamma Ray Measurements
Wireline gamma ray tools contain a gamma ray detector
but no gamma ray source. They measure the amount of
gamma radiation present in the subsurface environment.
The amount of such radiation emanating from a geologic
formation is usually a good indicator of the formation’s
shale volume, Vsh . Shale volume is used in determining
the formation’s sanding potential.
Gamma ray tools are often run in combination with sonic
and density tools. Either a conventional or spectral gamma
ray tool can be used. Conventional tools measure gamma
radiation in a single broad energy range while spectral tools
measure the amounts of gamma radiation in a large number
of energy bands. With spectral data, Vsh can be calculated
more accurately, and clay types can be identified.
Other tools are sometimes used to determine shale volume.
These include spontaneous potential, neutron, neutrondensity combination, and resistivity devices; however,
they will not be discussed here.
Formation Tester Measurements
Formation testers provide stationary measurements of
formation pressure. The tool is positioned at a depth at
which pressure is to be measured and is then held
stationary while pressure is recorded as a function of time.
This contrasts with most other logging tools, whose
Dipole Sonic Log
Figure 6.1 — Dipole sonic logs display both compressional and shear slowness curves, as in Track 2 of this
example. The compressional/shear acoustic velocity ratio and dynamic Poisson’s ratio are plotted in Track 3. The
acoustic velocity ratio is the reciprocal of the shear/compressional slowness ratio and is essential in calculating
the dynamic value of Poisson’s ratio and other rock properties. The Gamma Ray curve in Track 1 is used for
correlation with formations in offset wells, and the Caliper curve indicates severe washouts that could affect
the quality of sonic measurements.
67
FRACPAC COMPLETION SERVICES
measurements are usually recorded as a function of depth.
Analysis of pressure measurements yields reservoir pressure
and permeability. These parameters are used directly in
the FracPac simulation program.
Pore pressure, pp ′ is one of the most crucial parameters in
evaluating the stress field around the borehole. Although
the assumption of a 0.46-psi/ft pore pressure gradient is
accurate enough for most analyses, the exceptions will
cause erroneous stress profile calculations. For example,
overpressured zones and depleted zones drastically affect
the final stress profile. Although the pore pressure gradients
in such zones are generally known from reservoir engineering, the precise boundaries at which pressure gradients
change must be identified. This can be accomplished
using wireline formation tester or microfrac data. If such
data are not available, overpressured or depleted zones
may be detected using density, resistivity, or sonic logs.
Pore pressure gradients can vary on a smaller scale within
a reservoir or zone of interest, depending upon the density
of the fluid present. Although a slight gradient shift may
not be critical in the final stress evaluation, data from a
wireline formation tester should be used whenever it is
available. Density, resistivity, and sonic logs and reservoir
engineering data are usually not able to sufficiently resolve
variations in pore pressure gradients within an interval.
FRACTURING CALCULATIONS
Acoustic velocity ratio, Poisson’s ratio, Young’s modulus,
shear modulus, and bulk compressibility can be calculated
from tc , ts , and b . Equations 6.1 through 6.5 can be
used and the results displayed in a log format as in
Figure 6.2. In all the equations that follow, measurement
units must be compatible for calculations; otherwise,
conversion factors must be applied.
ts
Rv . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.1)
tc
where Rv is acoustic velocity ratio, ts is shear acoustic
slowness, and tc is compressional acoustic slowness. ∆ts
and tc are determined from wireline sonic tool
measurements.
2R v2
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.2)
2 1R v2
where is dynamic Poisson’s ratio.
68
b 43R v2 t 2 1R 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.3)
s
v
where E is dynamic Young’s modulus, and b is
formation bulk density determined from wireline
density tool measurements.
b
G ts 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.4)
where G is dynamic shear modulus.
3ts2
cb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.5)
b 3R v24
where cb is dynamic bulk compressibility.
The results from Equations 6.1 through 6.5 can then be
used to determine the formation’s effective radial,
tangential, and shear stresses and fracture closure
pressure. Biot’s constant, overburden pressure gradient,
and mud pressure must be calculated before the stresses
and fracture pressures can be found. Equations 6.6
through 6.8 outline the necessary relationships.
1cm
cb . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.6)
where is Biot’s constant, and cm is matrix compressibility, which can be determined from laboratory
measurements on full core samples or can be estimated.
Dfm
poG b dD . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.7)
D
0
where poG is overburden pressure gradient, D is depth,
and Dfm is the depth of the formation under study.
pm mDf m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.8)
where pm is mud or fluid pressure due to the mud or fluid
column in the wellbore, and m is the average mud or
fluid weight from the surface to the formation under study.
Formations stresses and fracturing pressures can now be
found with Equations 6.9 through 6.13. (Equations 6.9
through 6.12 are after Coates and Denoo.1) Log analysis
Rock Properties Log
Figure 6.2 — The Rock Properties log presents dynamic values of Poisson’s ratio, Young’s modulus, shear
modulus, and bulk compressibility (Tracks 3 and 4). It also displays an estimated static Poisson’s ratio (Track 3).
The sonic and density measurements on which the rock property calculations are based are shown in Track 2.
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FRACPAC COMPLETION SERVICES
FRACPRESSURE Log
Figure 6.3 — The FRACPRESSURE log provides estimates of the vertical extent that will be achieved
by a hydraulically induced fracture. In Track 3, formation lithology and fluid content are shown.
Track 1 plots a formation stress profile that helps identify stress contrasts and barriers to fracture
growth. In particular, the log displays fracture closure pressure, which is equal to the least principal
horizontal stress. Track 2 plots the fracture extension pressure and shows estimates of the vertical
height growth that will occur as pressure is increased in 200-psi increments.
70
programs such as Halliburton’s STRESS Module can
perform the necessary calculations and display the results
in log format as in Figure 6.3
r pm ppG Df m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.9)
Mohr's Circle Analysis
Linear Failure Envelope
where r is effective radial stress, and ppG is pore pressure
gradient, which can be determined from wireline
formation tester measurements.
D ra
pm Dfm ppG 2 poG ppG R
1 Failure Envelope
Shear
Initial
Shear Stress
wn
Envelope
Slope
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.10)
where is minimum effective tangential stress, and R is
the regional stress, which can be determined from
measurements on full cores or can be estimated.
wdo
Stress
Radial Stress
Tangential Stress
pfi t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.11)
where pf i is fracture initiation pressure, and t is tensile
strength, which can be determined from measurements
on full core samples.
pfc Dfm ppG 1 p
oG
Figure 6.4 — The drawdown pressure needed to calculate a
formation’s critical pressure can be found by determining the
distance between Mohr’s circle and the formation’s failure
envelope. The envelope can be linear or parabolic.
– ppG . . . . . . . (6.12)
where pfc is fracture closure pressure.
Tf
1
1
pfe2 pfe1 L
L
f2
f1
2
Lf 2
pfc2 pfc1 arccos . . . . . . . . . . . . . . . (6.13)
Lf 1
where pfe2 is the fracture extension pressure needed to extend
the fracture from one zone (Zone 1) into an adjacent zone
(Zone 2), pfe1 is the fracture extension pressure in Zone 1,
Tf is fracture toughness (a stress intensity factor at the ends
of the fracture), Lf2 is the fracture’s half-length after extension into Zone 2, Lf1 is the fracture’s half-length before
extension into Zone 2, pfc2 is the fracture closure pressure
in Zone 2, and pfc1 is the fracture closure pressure in Zone 1.
The log-derived Young’s modulus and fracture closure
pressure are used in the FracPac simulation program to
design the FracPac job. The program is built upon a
three-dimensional fracture model and is described in
Fracture Design Simulators (Chapter 7). Other STRESS
Module results are used in Halliburton’s Perforating
Planner Module (described in Chapter 11) to estimate
the downhole performance of perforating systems used in
FracPac completions.
SANDING CALCULATIONS
The log-derived stresses calculated in the previous section
are used in Mohr’s Circle analysis to predict formation
sanding potential. This analysis determines a formation’s
critical pressure, which is the pressure at which the
formation will experience shear failure. Critical pressure
varies with depth and can be calculated by subtracting
mud pressure from drawdown pressure, the latter of
which can be found from Mohr’s Circle analysis. As
shown in Figure 6.4, the distance between the Mohr
circle and the formation’s failure envelope (which can be
linear or parabolic) defines the drawdown pressure.
Critical pressure can be calculated from the relationships
in Equations 6.14 through 6.25 and then displayed on a
log as in Figure 6.5. (Equations 6.14 and 6.15 are after
Edwards, Sharma, and Charron.2)
71
FRACPAC COMPLETION SERVICES
Formation Strength Log
Figure 6.5 — A Sanding Potential and Formation Strength log shows the critical sanding pressure curve and
the maximum drilling pressure curve. Safe bottomhole pressures are indicated by the shaded area between
the curves. At pressures less than the critical pressure, sanding can occur; at pressures higher than the
maximum drilling pressure, formation fracturing can occur. The pore pressure curve gives the static pressure
of the fluid in the formation pore space, and the overburden pressure curve gives the pressure exerted by the
weight of overlying rock.
cu E 0.0045 1 Vsh 0.008Vsh . . . . . . . . . . . (6.14)
where cu is the uniaxial compressive strength, and Vsh is
the formation’s shale volume, which can be determined
from wireline gamma ray as well as other wireline
measurements.
0.025cu
si . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.15)
cb 106
where si is initial shear strength of the formation.
r
rM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.16)
2
where rM is the radius of Mohr’s circle and represents s ,
which is the net, or effective, shear stress on the formation.
The x-coordinate, xM , of the center of Mohr’s circle is
given by Equations 6.17 and 6.18.
xM s
when r . . . . . . . . . . . . . . . . . . (6.17)
xM r s
when r . . . . . . . . . . . . . . . . . . (6.18)
When the Mohr’s circle analysis involves a linear failure
envelope, Equations 6.19 through 6.21 are used.
72
m( r ) r
si
2
m
xi . . . . . . . . . . . . . . . . . . . . . (6.19)
1
m
m
where xi is the x-coordinate of the intersection of the
failure line with the Mohr’s circle radius that is tangent to
the failure line, and m is the slope of the failure line.
yi si mxi . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.20)
where yi is the y-coordinate of the intersection of the
failure line with the Mohr’s circle radius that is tangent
to the failure line.
RECOMMENDED LOGGING PROGRAM
Logging data should be recorded in open boreholes where
possible. A basic data set can still be gathered in a cased
well, but openhole data are more accurate and complete.
Openhole Environment
Sonic, density, formation tester, and gamma ray logs
should all be run in open holes. Small-diameter sonic,
density, and gamma ray tools rated for high-pressure,
high-temperature work are available for use in slimhole
applications and hostile environments. For example,
Halliburton’s HEAT Suite tools have 2.75-inch OD and
are rated to 25,000 psi and 500˚F.
2
dM x
y
x
2
i –
M
i . . . . . . . . . . . . . . . . . . . . . . . . . . (6.21)
where dM is the distance from the center of Mohr’s
circle to (xi ,yi ).
When a parabolic failure envelope is used in the Mohr’s
circle analysis, Equation 6.22 applies.
dM 2i
1
1 xM 2si . . . . . . . . . . . . (6.22)
si
where dM is the distance from the center of Mohr’s circle
to the intersection of the Mohr’s circle radius that is
tangent to the failure line, and is the offset of the
parabolic failure envelope. ( should be greater than
2si .)
For either a linear failure envelope or a parabolic failure
envelope, if dM > rM , then the formation is strong enough
to withstand stresses and remain intact; otherwise, there
is potential for sanding. Drawdown and critical pressures,
pdraw and pcrit , can be calculated from Equations 6.23
through 6.25.
pdraw dM rM
when r . . . . . . . . . . . . . . . (6.23)
pdraw dM rM
when r . . . . . . . . . . . . . . . (6.24)
pcrit pm pdraw . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.25)
Cased-Hole Environment
With the exception of density, all measurements made in
open holes can be made in cased wells. Because of the
presence of casing, however, special tools or tool configurations must sometimes be used.
In cased holes, full waveform sonic tools can provide
good measurements when there is good acoustic coupling
between casing and cement. This coupling serves to
damp the acoustic waves that are propagated through the
casing so they will not interfere with the acoustic waves
that are returning from the formation. The Full Wave
Sonic tool can be configured in an extra-long mode in
which the receivers are offset from the transmitter by
additional space. This increases the difference in arrival
times at the receivers between the casing waves and the
formation waves so that the two wave types are easier to
distinguish from one another. In certain cases, waveform
filtering may improve the measurements, even when the
casing-cement acoustic coupling is not optimal.
Casing is translucent to dipole acoustic energy. Dipole
tools can determine ts in cased wells, even when there is
no cement present between the casing and the formation.
However, in such an environment, tc cannot be measured
and must be obtained from an openhole log.
Formation bulk density cannot be measured in cased wells.
If an openhole density log is not available, density can be
estimated from compressional acoustic information, but
the accuracy of rock property and subsequent calculations
will diminish.
Special formation testers must be used in cased wells. They
contain explosive charges that penetrate casing and cement
to establish hydraulic communication between the tool and
73
FRACPAC COMPLETION SERVICES
the formation. Since these tools are configured with only
a few charges, they can measure formation pressure at only
a few discrete depths in the well. For instance, Halliburton’s
Cased Hole Formation Tester contains two perforating
charges, so it can record pressure at two different depths.
poG = overburden pressure gradient
pp = formation pore pressure
ppG = formation pore pressure gradient
rM = radius of Mohr’s circle
DATA TRANSFER
All logging data, computations, and analysis results are
stored on magnetic media and are easily transferrable among
personal computers, workstations, and mainframe computers.
NOMENCLATURE
cb = dynamic bulk compressibility
cm = matrix compressibility
cu = uniaxial compressive strength
D = depth
Df m = depth of subject formation
dM = distance from center of Mohr’s circle to the
point (xi ,yi) on the failure line
E = dynamic Young’s modulus
G = dynamic shear modulus
Tf = fracture toughness
Vsh = formation shale volume
xM = x-coordinate of the center of Mohr’s circle
(xi ,yI ) = coordinates of the intersection of the failure
line with the Mohr’s circle radius that is
tangent to the failure line
= Biot’s constant
tc = formation acoustic compressional slowness
tf = borehole fluid acoustic slowness
ts = formation acoustic shear slowness
= dynamic Poisson’s ratio
b = formation bulk density
Lf 1 = fracture half-length after extension into Zone 1
m = average mud or fluid weight from surface to
subject formation
Lf 2 = fracture half-length after extension into Zone 2
r = effective radial stress
pcrit = critical pressure
R = regional stress
pdraw = drawdown pressure
pfc = fracture closure pressure
si = initial formation shear strength
t = formation tensile strength
pfc1 = fracture closure pressure in Zone 1
= minimum effective tangential stress
pfc2 = fracture closure pressure in Zone 2
= offset of parabolic failure envelope in Mohr’s
circle analysis
pfe1 = pressure needed to extend fracture into Zone 1
pfe2 = pressure needed to extend fracture into Zone 2
pfi = fracture initiation pressure
pm = mud or fluid pressure due to the mud or fluid
column in the wellbore
po = overburden pressure
74
Rv = acoustic velocity ratio
REFERENCES
1. Coates, G.R., and Denoo, S.A.: “Mechanical Properties Program
Using Borehole Analysis and Mohr’s Circle,” Paper SPWLA 1981
DD, 1981 SPWLA Annual Logging Symposium, June.
2. Edwards, D.P., Sharma, Y., and Charron, A.: “Zones of Sand
Production Identified by Log-Derived Properties: A Case Study,”
Paper S, 1983 European Formation Evaluation Symposium, March.
Chapter 7
INTRODUCTION
The purpose of a fracture design
simulator is to use a computer to
simulate, as closely as possible, the actual
downhole events that occur while
performing a fracturing treatment.
Simulation allows design iterations, if
necessary, to optimize the treatment
design before starting expensive field
operations. Previously, using a simulator
to model tip-screenout designs, such as
those of FracPac Completion Services,
was a formidable task. Early simulators
had to be modified to account for the
significant amounts of proppant that
could be placed after the initiation of a
tip screenout and the higher proppant
concentrations and higher
conductivities that resulted from this
type of treatment.
A number of reliable fracture design
simulators are currently available for tipscreenout-design fracturing treatments.
The following discussion focuses on
three of the major programs that perform
tip-screenout fracturing design.
FRACPAC
The FRACPAC program has been
developed by Halliburton to assist in
the design of tip-screenout fracturing
treatments. The 3-D fracture geometry
predictions from the XTENT program
are incorporated with a modification to
FRACPAC that allows pumping to
continue after the tip screenout initiates.
Upon tip-screenout initiation, fracture
length extension and fracture height
extension stop and injection of additional
slurry causes fracture width to grow.
Calculations for fluid loss, fracture
width, proppant concentration, and
net treating pressure during pumping
continue after tip-screenout initiation.
Treatment modeling ends when the
user-specified increase in net treating
pressure is reached.
The FRACPAC design simulator offers
some very good input options such as
the capability of reading dynamic in-situ
rock stress measurements directly from
wireline logging files. The program also
has limitations, especially in complex
reservoirs. FRACPAC allows only one
pay zone to be analyzed, and even then
the stress values across the zone are
averaged. Values for fluid loss are also
limited. Only two values are allowed for
fluid loss: one value for the pay interval
and the other for outside the pay
interval. In wells where several highpermeability intervals are separated by
small layers of shale, FRACPAC requires
the user to make assumptions that can
cause the software to be difficult to use.
Fracture
Design
Simulators
STIMPLAN
The STIMPLAN program, developed by
NSI Inc., is a fracture design simulator
with special modifications that allow for
tip-screenout designs. At tip-screenout
initiation, fracture extension is stopped
and the program calculates a width
increase based on the increase in the
net treating pressure.
This program will analyze complex
formations composed of multiple
productive layers with varying fluid-loss
coefficients. STIMPLAN is welldesigned, easy to use, and is a popular
choice among the professionals who
need an effective tool for designing
fracturing treatments for highpermeability formations.
75
FRACPAC COMPLETION SERVICES
FRACPRO
The FRACPRO program was developed by Resources
Engineering Systems, Inc. (RES) with support from the
Gas Research Institute (GRI). This fracture design model
goes beyond standard simulators by acquiring real-time
fracturing data during treatment. The program can be
used to design fracturing treatments and then acquire
downhole data during field operations or from a
treatment database to confirm design estimates or
perform detailed posttreatment analysis. Changes to the
design and, if necessary, the treatment can be made to
better match job data to design criteria. The capabilities
of both designing, monitoring, and analyzing the
fracturing treatment make FRACPRO a versatile model
for both minifrac analysis and fracture design.
The FRACPRO model can analyze several layers of
formation with varying rock properties and fluid-loss
coefficients. Also, the model allows the user to select
either wall-building or nonwall-building fracturing fluids
to be used for the treatment. This fluid selection feature
is important, since both of these fluid types (HEC and
borate-crosslinked fluids) are used in high-permeability
formations. HEC does not build a filter cake and is
controlled by viscous invasion of the formation, whereas
borate-crosslinked fluids simulate a wall-building fluid
with high spurt volumes.
Multiple fluid designs can be handled with changing fluidloss coefficients and different fluid-loss characteristics of
the fracturing fluids. This feature is helpful when, for
example, a fracturing schedule is designed that calls for a
borate-crosslinked pad volume followed by a linear HEC
gel used to place the proppant.
RECOMMENDATIONS
Even more important than the selection of a particular
fracture-design program is consistency throughout the
design of a fracturing treatment. The model used to analyze
the minifrac test should also be used to design the main
fracturing treatment. Failure to be consistent with fracture
design software will almost always cause design errors due to
different geometry assumptions made in different programs.
For the design of fracturing treatments in high-permeability
formations, a 2-D fracture simulator should not be used.
A 2-D simulator can cause errors in the final fracturing
design by requiring many geometric assumptions on the
part of the user. Halliburton strongly recommends the use
of one of the three programs discussed and that the design
and analysis of minifrac tests and the main fracturing
schedule be implemented on the same software package.
76
Chapter 8
INTRODUCTION
Minifrac testing is performed before a
fracture stimulation to determine the
leakoff characteristics of the formation
and the selected fracturing fluid.
Determining leakoff characteristics is
especially critical when designing a tipscreenout fracturing treatment such as
FracPac Completion Services since
fluid leakoff is critical in determining
when and where the tip screenout occurs.
The high-permeability formations that
FracPac completions are designed for
show wide variations in fluid efficiency.
A successful FracPac treatment requires
the creation of a highly conductive,
wide fracture of adequate length. Such
fractures are best achieved through
initiating a tip screenout at the desired
distance from the wellbore, which
reduces the acceptable margin of error
in estimating the fluid-loss coefficient.
Short pumping times are characteristic
of FracPac treatments and further reduce
the error margins by not allowing time
to correct for errors in the fluid leakoff
estimates. Underestimating or overestimating the fluid leakoff can lead to either
a premature screenout or completion of
the treatment without achieving a tip
screenout. Both premature screenout
and a lack of a screenout do not achieve
the design requirements for length or
conductivity and are equally undesirable.
Therefore, performing and successfully
analyzing a minifrac test before the
main treatment is especially important
for FracPac applications.
SPECIAL CONCERNS OF
HIGH-PERMEABILITY
FORMATIONS
by a large spurt volume that is lost
before a filter cake builds up on the wall
of the fracture. The permeability of the
formation greatly affects the spurt volume
which may account for 60% to 90% of
the total fluid loss during the treatment.
Minifrac
Analysis
If fracturing fluids such as hydroxyethylcellulose (HEC) gels are used in highpermeability formations, a filter cake is
not formed on the formation wall. Fluid
leakoff behavior of HEC gels is governed
by non-Newtonian viscous invasion of
the fluid into the porous matrix and
does not follow the standard ti
me
function of wall-building gels. Fluidloss behavior of such gels cannot be
accurately modeled using a single fluidloss coefficient, and severe errors in
treatment design can result from using
such coefficients.
Current Recommendations
Halliburton strongly recommends
performance of a minifrac analysis before
conducting a fracturing treatment in
high-permeability formations. The fluid
efficiency and fluid leakoff coefficients
in high-permeability formations (greater
than 20 md) are not only extremely
sensitive to the average permeability of
the formation to be treated but also to
the permeability distribution and the
treating pressure. Therefore, the fluid
leakoff coefficients of the zone of interest
should be identified. Designing a FracPac
treatment does not allow the building of
any safety factors in the form of using
additional pad volume since the
additional fluid may prevent the onset
of the tip screenout and subsequent
packing of the fracture.
The fluid loss that occurs in high-permeability formations is often dominated
77
FRACPAC COMPLETION SERVICES
The current techniques for analyzing minifracs have
several assumptions that are valid for low-permeability
formations but lead to oversimplifications in highpermeability formations. Until more accurate techniques
are developed to analyze minifracs in high-permeability
formations, conventional analysis techniques should be
used with the understanding that they may result in
significant errors in fluid leakoff characterization.
Live Annulus Pressure (psi)
Pressure Decline
1,000
800
600
400
70-lb/Mgal HEC at 125°F
200
0
0
1
2
Square Root of Time ( min )
3
Figure 8.1 — This pressure-decline curve is plotted versus the
square root of time. The fracture closed in just under 1 minute in
the test performed.
G-Function Plot
Pressure (psi)
1,000
800
70-lb/Mgal HEC at 125°F
600
400
1.0
1.2
1.4
1.6
1.8
G-Function (dimensionless)
2.0
Figure 8.2 — Pressure (pressure decline) can also be plotted
versus the G-function (dimensionless).
Horner Plot Analysis
3,000
Bottomhole Pressure (psi)
High-permeability formations tend to have lower net
pressures and shorter closure times as opposed to lowpermeability formations. Closure times of 1 minute or
less are common. Correctly determining closure pressure
and closure time is more difficult in high-permeability
formations and is also more critical to designing an
effective fracturing treatment. A major concern of analyzing
minifrac tests in high-permeability formations is the
nature of the fluid loss. The manner in which the pressure
decline is analyzed depends on the type of fluid (linear gel
or crosslinked fluid) that is used in the minifrac.
200
0
2,800
2,600
2,400
2,200
2,000
1,800
1
10
Horner Time Log ((tp+dt)/dt)
100
Figure 8.3 — The data from Figure 8.1 and Figure 8.2 can be
plotted on a Horner plot.
78
Analysis of Pressure Decline by
Determining Closure Pressure and
Closure Time
Linear gels such as HEC do not build up a filter cake on
the fracture face, while crosslinked fluids may be associated
with high spurt-loss volumes. Assumptions that the
spurt-loss characteristics of a formation are negligible,
instantaneous, or do not affect the pressure decline have
been made while analyzing tests in low-permeability
formations. In high-permeability formations, however,
spurt times can be as long as the fracture closure times,
and the spurt volume can account for 40% to 90% of the
fluid loss of the treatment.
A conventional technique for analyzing minifrac tests is
currently being utilized for high-permeability applications
such as FracPac treatments. This method plots the shutin pressure versus the square root of time, or the shut-in
pressure versus the G-function. The straight-line
deviation determines the closure time and closure pressure.
The G-function or the ti
me plot should only be used to
identify fracture closure as accurately as possible. Using a
single fluid-loss coefficient (Ceff ) determined from the
slope of the G-function plot can lead to severe errors in
treatment design. The errors are due to the differing
leakoff characteristics of the linear and crosslinked fluids.
Crosslinked fluid behavior deviates significantly from the
assumptions made by using a single fluid-loss coefficient.
A Horner plot can be used to help confirm closure
pressure. In the Horner plot, pressure is plotted against
Horner time (dimensionless) as shown in Figure 8.3. The
linear portion of the graph indicates pseudoradial flow,
thus implying fracture closure. The deviation from the
straight line can yield the closure time and pressure. The
use of this method for all types of formations is
inconclusive since an insufficient amount of data exists to
prove the validity of this approach. However, the use of
the Horner plot in conjunction with the pressure-versus
ti
me plot may provide useful information.
When HEC fluids or other linear gels are used without
fluid-loss additives, the pressure-decline curve must be
analyzed with care since leakoff behavior is highly pressure
dependent. Current minifrac analysis methods are also
insufficient for crosslinked fluids, and new analysis
methods are under development.
Determining Fluid Efficiency and FluidLoss Coefficients
Until more accurate analysis techniques are developed for
all fracturing fluids, conventional techniques should be
used to determine closure pressure and closure time. To
effectively design a tip screenout, the fracture design model
should also be used to analyze the minifrac test. The
following procedure is suggested:
1. Use the fracture design model to simulate the minifrac.
Adjust the appropriate input parameters to match the
net pressure during the entire pumping treatment or
at least at the instantaneous shut-in pressure (ISIP).
Match the time for the fracture to close.
2. Most reservoirs require adjustments to fluid loss (or
permeability) and stress inputs. Use the information in
the following section as a guide to select the proper
fluid-loss properties for modeling. Using incorrect
fluid properties when performing a minifrac analysis
in high-permeability formation can result in large
errors. Such errors can also occur when using incorrect
fluid properties or if the job size is changed. Based on
data from current laboratory testing, the following
procedures are recommended for the various types of
fracturing fluids.
Cw and Spurt - Fluid Loss Match
6
Volume/Area (gal/ft2)
Figure 8.1 and 8.2 show a typical pressure decline for an
HEC gel versus ti
m
e plot and as a conventional Gfunction plot, respectively. The fracture closed in just
under 1 minute which made it difficult to analyze these
data.
Cvc
4
Cw
2
Vol
0
0
2
4
Square Root of Time ( min )
6
Figure 8.4 — In fracture design models that require a Cw and
spurt or a Ceff value, the Cw spurt option should be used. Built-in
calculations of the design simulator account for the effects of
reservoir-fluid viscosity and compressibility on fluid loss, while
adjusting only fracturing-fluid effects. Fluid-loss options such as
Ceff that override built-in reservoir calculations should not be
used. Linear gels can be modeled as power-law fluids. Fluid loss
is controlled by the viscous invasion into the formation and by
reservoir compressibility (CVC ).
The results of a series of dynamic fluid-loss tests performed
in many different permeabilities shows that while Cw
remains fairly constant, the spurt volume changes dramatically as the permeability increases. Therefore, for boratecrosslinked fluids, the book value for Cw should be used.
The spurt volume should be adjusted until a match is
achieved. Refer to Figure 8.4 for the results of fluid-loss tests
on borate-crosslinked fluids. The subsequent design should
then be completed using both a spurt volume and Cw .
Linear Fluids
With an appropriate viscosity for the leaked-off fluid, this
option can be used for fracture design models that have a
nonwall-building fluid. With fracture design models that
require Cw and spurt or a Ceff value, the Cw-Spurt option
should be used. The recommended procedure is to match
a Cw and spurt to the fluid loss calculated from Equation
9.1 in Chapter 9, Appendix A. If this does not result in a
match with the observed closure time and pressure, the
permeability of the formation must be changed, and a new
value for spurt volume and Cw should be estimated. This
is an iterative procedure that can be time-consuming but
can be performed by using a spreadsheet. Some Cw and
spurt volumes that provide a best data fit for the minifrac
79
FRACPAC COMPLETION SERVICES
analysis may not be the best values for the main fracturing
treatment if the job sizes are significantly different. Refer
to Figure 8.4 for an example of this technique. This
analytical procedure allows the built-in calculations of the
fracture design simulator to account for the effects of
reservoir-fluid viscosity and compressibility on fluid loss,
while adjusting only fracturing-fluid effects. Fluid-loss
options that override these reservoir-based calculations
(such as Ceff ) should not be used.
Fluid Loss of Linear Gels
When a linear gel is used in high-permeability formations
(greater that 20 md), the fluid does not form a filter cake
at the formation wall unless fluid-loss additives are used.
If a linear gel is used, the fluid loss is controlled by the
viscous invasion of the fluid into the formation and the
reservoir compressibility (CVC ). The rheological properties
of most linear gels allow them to be modeled as powerlaw fluids. Leakoff is described by
n′
60t
(8.1)
NOMENCLATURE
= porosity
81015k
n′ + 1
Fluid-loss test results indicate that fluid loss in highpermeability formations is characterized by filter-cake
buildup and high spurt loss. Thus, conventional minifrac
testing and analysis may not be sufficient to predict fluid
loss. The insufficiency comes from the calculation of only
a single fluid-loss coefficient (Ceff ). Corrections for the
spurt loss can be made if the value is determined from
laboratory data, but this method is an approximation.
The spurt volume is a function of several formation
variables and a better value can be determined from field
data. A method has been developed to calculate both the
Cw and average spurt loss (Vsp ) using a dual pump-in and
shut-in technique. This technique should be used,
whenever possible, to calculate these important variables
and ultimately achieve a more efficient fracture treatment
design.
= rock factor
n′
1
n′
1
72p n′ + 1 n′ + 1
V 3n′
1
K ′
Fluid Loss of Crosslinked Fluids
.............................
p = pressure drop (psi)
k = permeability (md)
K′ = consistency index (lbf - secn/ft2 )
n′ = flow behavior index
t = time (min)
or
n′
n ′ + 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (8.2)
V vt where V is leakoff volume per unit area (m3/m2), n′ is
flow behavior index, K′ is consistency index (lbf secn/ft2), is rock factor, p is pressure drop (psi), k is
permeability (md), is porosity, and t is time (min).
These equations give a leakoff profile characterized by
Figure 8.4. Conventional models may be inaccurate for
linear gels since they assume that the leakoff volume is
proportional to the ti
m
e.
80
V = leakoff volume per unit area (m3/m2 )
Ceff = overall fluid-loss coefficient
Cw = filter-cake coefficient
Cvc = reservoir compressibility
Vsp = average spurt loss
Chapter 9
INTRODUCTION
The proper selection of fracturing fluid
is one of the most critical elements in
FracPac Completion Services design. To
select the proper fluid, concerns such as
fluid-loss control, fracture conductivity,
formation damage, and proppant
transport must be considered.
Extensive testing has been conducted
to promote better understanding of
fracturing-fluid behavior in treatments
of high-permeability formations. In
these tests, the fluids were evaluated for
fluid-loss properties, regained permeability (formation damage), and fracture
conductivity. The results from these tests
have proven very helpful in making the
best fluid selection for a given well.
The first portion of this chapter focuses
on Halliburton’s recommendations for
fracturing fluids based on test data. Later
in the chapter, types of fluid systems,
additives, and the general behavior of
these fluid systems is discussed.
Appendices present the models used to
characterize the fluids and quality
assurance measures that can be applied
to make FracPac most effective.
CONCLUSIONS AND
RECOMMENDATIONS
The results from formation-damage tests
and fracture-conductivity tests 1, 2 have
shown hydroxyethyl cellulose (HEC)
to be the most applicable linear gel for
FracPac treatments. Borate-crosslinked
hydroxypropyl guar (HPG) gels were
found to be the most effective crosslinked
fluid system for FracPac Completion
Services. The use of either a linear gel
or a crosslinked gel is very dependent
on the formation permeability,
reservoir fluid, and reservoir pressure of
the candidate well. Table 9.1 summarizes
the fluids and conditions that were tested
to develop the fluid-selection criteria for
FracPac applications. Figure 9.1 shows
the recommended fluids for different
formations based on permeability and
reservoir type.
Fracturing
Fluid
Systems
Formation damage and fracture
conductivity studies have shown that
breakers should be in solution when
fracturing high-permeability formations
so that the entire crosslinked gel volume
that leaks off into the formation can be
effectively broken. Fracture conductivity
can be enhanced if an encapsulated
breaker is placed in the proppant pack.
Some unique well conditions may
require the use of fluid systems that are
different from the HEC linear gel and
borate-crosslinked HPG gel prescribed
previously as most applicable to all
FracPac procedures. For this reason a
complete summary of all the fluid
systems tested and the properties of each
are discussed in the following sections.
AVAILABLE FLUID
SYSTEMS
As many as 50 different fluids have been
developed to solve various needs within
the oil- and gas-well stimulation and
completion markets.3- 21 The major types
of fluids that remain at the backbone of
the industry are as follows:
• Conventional linear gels
• Borate-crosslinked fluids
• Organometallic-crosslinked fluids
• Aluminum phosphate-ester oil gels
81
FRACPAC COMPLETION SERVICES
Table 9.1 — Fracturing Fluids Evaluated in the Study
Fluid System
Temperature (°F)
70-lb HEC
120
1-lb SP/Activator
70-lb HEC/40-lb Silica Flour
120
1-lb SP/Activator
30-lb HPG/Borate
120
1-lb SP/Activator
Gelled Oil System
120
NONE
70-lb HEC
180
0.2-lb SP
70-lb HEC/40-lb Silica Flour
180
0.2-lb SP
70-lb HEC
180
0.75-lb SP
70-lb guar
180
0.2-lb SP
40-lb HPG/Titanate
180
0.2-lb SP
40-lb HPG/Borate
180
0.2-lb SP
40-lb CMHPG/Zirconate
180
0.75-lb SP
40-lb CMHEC/Zirconate
180
0.4-lb SP
40-lb HPG/Titanate
240
NONE
40-lb HEC/Borate
240
NONE
All of these fluids may be run as two-phase systems, since
they all are compatible with nitrogen. However, only the
linear gels and some of the organometallic-crosslinked
fluids are compatible with carbon dioxide. A brief
description of each of the fluid systems listed above and
how they can be applied in high-permeability fracturing
treatments is included in the following sections.
Conventional Linear Gels
Conventional linear gels are very simple to use and can
be formulated with a wide array of different polymers and
fluids. Common polymer sources used with the linear
gels are guar, HPG, HEC, carboxymethylhydroxypropyl
guar (CMHPG), and carboxymethylhydroxyethyl
cellulose (CMHEC).
Previous studies performed with these fluids have indicated
that gel residue from guar fluids can be as high as 8% to
10% by weight. The high residue content of guar gels can
cause permeability reduction in the proppant pack of the
fracture, if further cleanup measures are not applied. 22,23
Similar problems have been observed with linear HPG
and CMHPG, though the resultant damage is not as
extreme with this type of fluid system. In both HPG and
82
Breaker Concentration
CMHPG fluids, the residue content can be from 1% to
3% by weight. HEC fluid sytems are virtually residue free
and provide the best proppant-pack permeability.
The general characteristics of linear gels are poor proppant
transport and low fluid viscosity. In lower-permeability
formations (less than 0.1 md), linear gels control fluid loss
very well, whereas in higher-permeability formations fluid
loss can be excessive. Linear gels tend to form thick filter
cakes on the face of lower-permeability formations, which
can adversely affect fracture conductivity. The performance
of linear gels in higher-permeability formations is just the
opposite, since it forms no filter cake on the formation wall.
Much higher volumes of fluid are lost due to viscous
invasion of the gel into the formation. Fracture conductivity
can be much higher when linear gels such as HEC are used.
New biopolymer gel systems have been recently added to
the selection of gravel pack fluids. These biopolymer
systems offer interesting properties for FracPac applications
also. These fluids feature clean, controllable breaks that
result in excellent regained permeability and fracture
conductivity. The new biopolymer systems that have been
tested to date2 have had restricted use in FracPac
treatments because of their high cost and unfavorable
shear-thinning properties.
Borate-Crosslinked Fluids
700
600
Permeability (md)
Borate-crosslinked fluids were once restricted from hightemperature applications, but advances have improved
them for use in temperatures to 300°F.24, 6, 7 The polymers
most often used in these fluids are guar and HPG. The
crosslink obtained by using borate is reversible and is
triggered by altering the pH of the fluid system. The
reversible characteristic of the crosslink in borate fluids
helps them clean up more effectively, resulting in good
regained permeability and conductivity. In addition to
good cleanup properties, with the proper composition,
borate fluids provide good proppant transport, stable
fluid rheology, and low fluid loss. The use of boratecrosslinked fluids has increased significantly over the last
decade, and HPG-borates show great potential for highpermeability applications.
500
400
300
200
100
0
Oil
Gas
Organometallic-Crosslinked Fluids
Organometallic-crosslinked fluids have long been the most
popular class of fracturing fluids. Primary fluids that are
widely used are titanate and zirconate complexes of guar,
HPG, CMHPG, or CMHEC. These fluids are extremely
stable at high temperatures and are currently the only
type of fluids that can be used at bottomhole temperatures
that exceed 300°F.
The proppant transport capabilities of organometalliccrosslinked fluids are excellent, and these fluids form a very
resilient filter cake on the face of the fracture. The metallic
bonds which form the crosslink mechanism in these fluids
are not reversible and do not break when exposed to
conventional gel-breaking systems. Because of the strong
bonds of these fluids, the filter cakes deposited on the
fracture face can be more difficult to clean up and can result
in impaired fracture conductivity. Cleanup difficulty is the
major disadvantage to these types of fracturing fluids; thus,
their use in high-permeability formations is a questionable
practice. When carbon dioxide is used or when dealing with
high reservoir temperatures, organometallic-crosslinked
fluids may be necessary despite cleanup difficulties.
HEC
Formation
Dependent
Borate
(HPG)
Figure 9.1 — Formation type and permeability play a major role
in fracturing fluid selection. Fluid recommendations are shown
based on formation permeability for both oil and gas reservoirs.
there are greater concerns regarding personnel safety and
environmental impact, as compared to most water-fluids.
In wells with high-permeability formations, the advantages
of using gelled oils can outweigh their disadvantages, if
safety and environmental issues can be resolved.
Foamed and Other Fluids
Other fluids such as polymer-emulsion systems and gasenergized systems exist, but they have limited application in
high-permeability formations due to environmental, safety,
or equipment limitations. Foamed or energized fluids
may be especially useful for FracPac treatments of highpermeability formations in low-pressure gas reservoirs.
Aluminum Phospate-Ester Oil Gels
Gelled oil systems were the first high-viscosity fluids used
in hydraulic fracturing operations. A major advantage to
this type of fluid is its compatibility with almost any
formation type. There are some disadvantages in using
gelled oils. Gelling problems can occur when using crude
oils and the cost of using refined oils is very high. Also
BREAKERS
For high-permeability fracturing applications, use of the
proper gel breaker system is crucial to realizing maximum
regained permeability and fracture conductivity. In lowpermeability applications, the use of delayed, encapsulated
breakers has proven very effective in breaking the filter
83
FRACPAC COMPLETION SERVICES
High-permeability treatments require the use of breakers
which are in solution with the gel systems, so that even the
gel which leaks off into the formation is completely broken
at the proper time. Halliburton still recommends that
additional encapsulated breaker be mixed into the
proppant-bearing stages of the treatment. This helps
ensure that an adequate amount of breaker is present to
break the filter cake on the fracture face and thus
maximizes fracture conductivity.
Filtrate Volume Per Area (ml/cm2)
Fluid Loss at 120°F
15
70-lb HEC / 40-lb Silica Flour
10
Gelled Oil System
70-lb HEC
5
30-lb HPG / Borate
0
0
1
2
3
4
5
6
7
Square Root of Time ( min)
8
9
Figure 9.2 — Selection of the proper treatment fluid is the most
effective means of controlling fluid loss in high-permeability
formations. The borate-crosslinked fluids have proven themselves
superior in high-permeability formations, both with high fluidloss efficiency and easy cleanup.
cake on the formation face and maximizing fracture
conductivity. High-permeability applications, however,
result in the invasion of a viscous gel into the formation
and pose the additional concerns which follow:
• Encapsulated breakers “plate out” on the fracture face or
stay in the proppant bed, which helps break the filter
cake and gel in the proppant pack. This type of breaker
does not help break the gel that enters the formation.
• The damage caused by viscous invasion of the gel can
be serious if the gel remains unbroken in the formation.
A reduction in regained permeability is the first potential
source of formation damage, since the unbroken gel
blocks the pore spaces in the formation. A second
potential source of damage can be caused by the flow
of unbroken gel from the formation into the proppant
pack, which can reduce fracture conductivity.
• Cleanup time can be drastically increased, sometimes
requiring several days or weeks to recover the load fluid
from the fracturing treatment. Producing the well at
higher drawdown pressure is sometimes attempted to
speed up the load-fluid recovery. These higher drawdown
pressures can apply additional stress to the formation
and result in early sand production, which negates the
effect of the fracturing treatment.
84
Break testing should be performed before the job is pumped.
These tests help ensure that break times are sufficient to
place the treatment, but short enough to allow the well to
be put on production and cleaned up in a reasonable
amount of time. The breaker schedule should provide
good fluid properties for twice the anticipated pump time
and a complete break in 2 to 4 hours.
Halliburton has tested a new procedure in which a dual
fluid system is pumped. In this procedure, a high-efficiency
pad volume is pumped, followed by a low-efficiency
proppant placement fluid. This dual-stage approach is
designed to more effectively place proppant into the
created fracture, particularly in very high-permeability
formations where it may not be possible to create adequate
geometry with a linear gel. Test results have indicated
that the fluid used to place the proppant can be chosen so
that it will effectively break the filter cake of the pad fluid
and greatly increase the fluid leakoff rate. Proper fluid
selection makes it possible to control the amount of fluid
loss while pumping the pad volume, thus allowing the
desired fracture length and width to be created using smaller
pad volumes. For example, using a borate-crosslinked fluid
system improves the fluid-loss control and increases the
fluid efficiency of the pad volume. Following the borate
system with a pH-buffered HEC for proppant placement
will help reverse the filter cake formed by the borate fluid
and break the crosslink of the borate gel that leaked off
into the formation. There are several benefits to this
approach. Overall, less fluid is required to be pumped,
minimizing potential formation damage. The linear HEC
gel within the proppant bed provides maximum fracture
conductivity. This dual-fluid technique, if applied with a
well-designed breaker schedule, can result in reduced
formation damage and maximum fracture conductivity.
This technique allows the use of HEC as well as other
gelling agents for the linear gel stage. The same benefits
can be obtained by using the borate-crosslinker and
buffering the base gel.
FLUID LOSS
Fluid-loss testing has shown that crosslinked fluids are far
superior to linear gel systems for reducing fluid loss in highpermeability formations. Comparison of fluid loss using
crosslinked gels shows that the borate-crosslinked fluids are
particularly more efficient than any of the organometallic
systems tested. The high fluid-loss efficiency of the borate
fluids, plus the advantages of their reversible crosslink and
their easy cleanup, has made them the preferred choice
for crosslinked gels. Based on these test results and on
field results, borate-crosslinked fluids are highly
recommended in high-permeability wells where HEC
performs poorly.
Viscous fluid invasion predominantly controls fluid loss in
high-permeability formations more so than in conventional
fracturing in low-permeability formations. As a result of
this fluid-loss behavior, the performance of linear gels and
crosslinked gels is very different and is discussed in detail
in the following sections.
Linear HEC Fluids
In formations with permeability that exceeds 20 md, the
fluid-loss behavior of linear HEC gel systems is completely
governed by the invasion of the whole gel into the
formation. A filter cake does not build up on the faces of
the fracture, and the leakoff rate is controlled by the
rheological behavior of the gel in the porous medium.
HEC gels have been observed to behave as power-law fluids
in high-permeability formations. A plot of the measured
apparent viscosity versus shear rate in a test core for an
HEC fluid system is shown in Figure 9.3. A model for the
leakoff of a power-law fluid was developed based on test
results and appears in Appendix A at the end of this chapter.
The non-Newtonian power-law nature of fluid leakoff in
high-permeability formations has led to some interesting
insights into its fluid leakoff behavior. One consequence
of using non-Newtonian fluids is that their leakoff can
100
Berea Sandstone,
Rock Factor = 0.577
Apparent Viscosity (cp)
Dynamic fluid-loss studies performed on high-permeability
cores 1,2,21,33 have provided very useful information about
fluid-loss properties as a function of gel type and formation
properties. These test results have indicated that in highpermeability rock, selection of a proper treatment fluid is
the most effective means of controlling fluid loss. In most
cases, the use of a particulate-type fluid-loss additive can
improve the fluid loss to the formation; however, these
types of additives can damage fracture conductivity
during production (Figure 9.2).
HEC Gel
Apparent Viscosity vs. Shear Rate
Berea Sandstone,
Rock Factor = 0.659
Viscometer data
10
100
1,000
Shear Rate (1/s)
10,000
Figure 9.3 — A plot of apparent viscosity versus shear rate for
an HEC fluid shows that these gels behave as power-law fluids in
high-permeability formations.
decrease faster over time than that of a Newtonian fluid.
As a non-Newtonian fluid invades the formation rock, the
shear rate inside the porous media is very high, typically
about 10,000/sec. As the depth of fluid invasion increases,
the filtrate rate decreases as does the shear rate within the
rock. The fluid’s apparent viscosity increases with the
decreasing shear rate due to the fluid’s shear-thinning
nature. The increase in apparent viscosity aids in
controlling fluid leakoff. This fluid behavior also implies
that high-permeability treatments with linear gels should
have higher fluid efficiencies than predicted with a single
value of CVC and that using fluids that are highly nonNewtonian in nature (lower values of n ′) may provide
lower fluid efficiency.
Guar-Based Linear Gels
Some guar-based gels such as HPG show the same
nonwall-building characteristics as HEC fluids in high
permeability. However, guar gel tends to build a filter
cake, and most tend to develop a better filter cake than
the HEC fluids. This wall-building tendency has a
complex leakoff function that is initially governed by
viscous invasion of a non-Newtonian fluid and then
changes over time to a system dominated by filter cake.
This tendency to develop a filter cake with guar fluids is
believed to be due to the high residue content of this
fluid as compared to HEC. The filter-cake buildup and
the deeper formation damage makes guar unsuitable for
FracPac applications. HPG and CMHPG are usable
FracPac fluids due to their lower gel-residue content.
These fluids, however, do not perform as well as HEC.
85
FRACPAC COMPLETION SERVICES
Table 9.2 — Fluid Loss Results
Core Perm
Invasion
Vspt
Cw
Temp
(ft/m
in )
(°F)
Fluid
(md)
Depth (in.)
(gal/ft2)
70-lb HEC/40-lb Silica Flour
191
3
2.970
0.00328
120
170 - 420
1.1
0.404
0.00223
120
Gelled Oil System
200
3.1 & 5.1
1.060
0.01181
120
70-lb HEC
6.45
6
0.790
0.00492
180
70-lb guar
30-lb HPG/Borate
120
5
0.500
0.00115
180
70-lb HEC/40-lb Silica Flour
400
6
5.290
0.00492
180
40-lb HPG/Borate
7.9
3.1
0.110
0.00164
180
40-lb HPG/Borate
170 - 230
1.1
0.077
0.00279
180
40-lb HPG/Borate
1,100
1.1
0.559
0.00295
180
40-lb HPG/Titanate
452
3.1
0.837
0.00230
180
40-lb CMHPG/Zirconate
380
3.1
0.677
0.00459
180
40-lb CMHEC/Zirconate
380
1.1
0.383
0.00197
180
40-lb HPG/Borate
184
3.1
0.392
0.00262
240
40-lb HPG/Titanate
125
3.1
0.736
0.00295
240
Fluid Loss at 240°F
Filtrate Volume Per Area (mL/cm2)
25
70-lb HEC /40-lb Silica Flour
20
15
70-lb HEC
40-lb CMHPG / Zirconate
)
Filtrate Volume Per Area (mL/cm2
Fluid Loss at 180°F
40-lb HPG / Titanate
10
40-lb CMHEC / Zirconate
40-lb HPG / Borate
5
0
0
5
10
15
20
Square Root of Time ( min)
25
Figure 9.4 — The filtrate volume data from fluid-loss tests made
at 180°F were plotted. Tests of all the fluids were run on Berea
sandstone cores.
86
5
40-lb HPG /Titanate
4
3
0
2
40-lb HPG /Borate
1
0
1
2
3
4
5
6
Square Root of Time ( min)
7
Figure 9.5 — The filtrate volume data from fluid-loss
tests made at 240°F were plotted. Tests of all the fluids
were run on Berea sandstone cores.
8
A very important factor about this type of fracturing fluid
system is that although the results of fluid-loss tests have
followed the classical models of spurt loss followed by
filter-cake formation, very high spurt volumes and long
spurt times are observed in high-permeability cores. All
observations suggest that even with the high viscosity of
crosslinked fluid systems, the early leakoff rate is primarily
governed by viscous invasion of the gel into the formation.
The depth of formation invasion and the amount of time
required to build a filter cake appears to be a complex
function of the formation permeability, fluid viscosity,
and differential pressure. Crosslinked gels do not invade
the formation as deeply as linear gels, but they do develop
a very concentrated buildup in the formation near the
fracture face, which can be very difficult to clean up.
Viscous invasion of the formation by crosslinked fluids
has been observed to govern fluid loss until a filter-cake
formation occurs. Compared to linear gels, the higher
viscosity crosslinked fluids consistently have shown lower
fluid loss and shallower invasion of filtrate into the cores
tested. Classical fluid-loss models can be used to model the
leakoff of crosslinked fluids in high-permeability formations,
but the early spurt volumes are very significant and should
not be ignored when designing a fracturing treatment.
Fluid-loss test results are summarized in Table 9.2. Test
data are shown in Figure 9.4 through Figure 9.6.
Volume Per Area (ml/cm2)
Crosslinked fluid systems that were tested showed filter
cake formation and followed the more classical ti
m
e
models for fluid loss. (Refer to Appendix A at the end of
this chapter for models of fluid behavior.)
500
5
Volume Per Area
4
400
300
3
Region 1
2
200
Region 2
Region 3
100
1
0
0
0
1
2
3
4
5
6
7
Square Root of Leakoff Time ( min)
8
Pressure Drop Per Length (psi/cm)
HPG/ Titanate Gel Filtrate
Volume vs. Pressure Drop
Crosslinked Fluid Systems
Figure 9.6 — The filtrate volume and the pressure drop across
the first three zones of the core were measured during the fluidloss test. The test was performed with 40-lb HPG/Mgal+Titanate
at 180°F in Berea sandstone.
FORMATION DAMAGE
The fluid-loss test results discussed previously indicate that
fracturing fluids behave very differently in high-permeability
formations than in low-permeability formations. The
viscous invasion of the gels into the formation is a
significant variation from behavior in conventional, lowpermeability formations and has been investigated. A
multiport Hassler sleeve was used as a laboratory tool to
monitor the depth of invasion during static fluid-loss tests.
The flow was then reversed through the sleeve (and the
core being tested) to evaluate the regained permeability at
various regions of the core as shown in Figure 9.7. These
Core Configuration
Perm
Direction
2.1 cm
5.1 cm
5.1 cm
2.8 cm
Region
4
Region
3
Region
2
Region
1
Fluid Loss
Direction
Distance = 15.1 cm
Figure 9.7 — The cores used in the fluid-loss tests and the formation-damage tests were divided into the
regions shown to measure the depth of formation damage. The fluid-loss direction and the permeability
direction (which is the direction in which formation damage occurs) are exactly the opposite.
87
FRACPAC COMPLETION SERVICES
Table 9.3 — Formation Damage Results
Overall Perm
Temp
(md)
Region
Regain
(°F)
70-lb HEC
230
1
2
3
31
28
30
120
70-lb HEC/40-lb Silica Flour
191
1
2
3
26
40
39
120
30-lb HPG/Borate
420
1
2
3
18
43
55
120
Gelled Oil System
200
1
2
3
24
22
68
120
70-lb HEC
6.45
1
2
3
26
23
29
180
70-lb HEC
160
1
2
3
30
43
44
180
70-lb HEC
1200
1
2
3
47
57
37
180
70-lb HPG
159
1
2
3
3.6
9.8
19
180
70-lb guar
120
1
2
3
0.8
5.8
18
180
70-lb HEC/40-lb Silica Flour
400
1
2
3
5
27
36
180
40-lb HPG/Borate
7.9
1
2
3
85
71
94
180
40-lb HPG/Borate
170
1
2
3
44
63
65
180
40-lb HPG/Borate
1100
1
2
3
1.9
88
91
180
40-lb HPG/Titanate
452
1
2
3
0.1
0.2
8.8
180
40-lb CMHPG/Zirconate
380
1
2
3
4
76
62
180
40-lb CMHEC/Zirconate
380
1
2
3
13
14
42
180
40-lb HPC/Borate
184
1
2
3
74
44
59
240
40-lb HPG/Titanate
125
1
2
3
3.1
5.1
45
240
Fluid Type
88
Percentage
Table 9.4 — Fracture Conductivity Results (md-ft)
Temp
Fluid
Core Type
2,000 psi
4,000 psi
(°F)
70-lb HEC
Berea
6,685
2,875
120
70-lb HEC/40-lb Silica Flour
Berea
4,516
1,869
120
30-lb HPG/Borate
Berea
5,128
2,167
120
Gelled Oil System
Berea
4,527
2,579
120
70-lb HEC
Texas Creme
5,939
1,537
180
70-lb HEC
Berea
6,516
2,891
180
70-lb HEC
Brown
7,239
3,112
180
70-lb HPG
Berea
3,154
922
180
70-lb guar
Berea
559
176
180
70-lb HEC/40-lb Silica Flour
Berea
4,302
1,423
180
40-lb HPG/Borate
Texas Creme
3,235
1,045
180
40-lb HPG/Borate
Berea
2,441
757
180
40-lb HPG/Borate
Brown
3,740
1,358
180
40-lb HPG/Titanate
Berea
3,446
1,046
180
40-lb CMHPG/Zirconate
Berea
1,626
519
180
40-lb CMHEC/Zirconate
Berea
941
611
180
40-lb HPG/Mgal + Titanate
Berea
3,162
845
240
40-lb HPG/Mgal + Borate
Berea
573
260
240
formation-damage tests (to determine regained permeability)
were conducted at several different temperatures with
selected fluids. Results of these tests are listed in Table 9.3.
• Temperature limitations of HEC restrict its use to
temperatures less than 180°F, while borate-crosslinked
fluids remain effective up to 300°F.
Formation-damage test results were very consistent and
show HEC and borate-crosslinked gels to cause the least
amount of damage. Although core invasion was very deep
with the HEC fluid, the very low residue content of this
fluid allows it to flow back very efficiently. The linear
guar-based gels show deep invasion and high residue
content; the combination of these factors causes severe
formation damage. Crosslinked gel systems, in general,
show much less depth of invasion. Using the boratecrosslinked fluids, with their high viscosity, results in less
invasion than use of organometallic fluid systems. Also,
the borate fluids clean up much more easily than the
organometallic fluids, and give overall better results in
high-permeability formations.
• HEC shows low damage to high-permeability formations.
Borate-crosslinked gels show less permeability recovery
than do HEC fluids.
Based on the results of the formation-damage studies, the
following general observations and recommendations
were made:
• Depth of invasion for HEC can be great due to poor
fluid-loss control and some deeper damage can result.
Invasion depths from using borate-crosslinked fluids in
high-permeability formations are significant and can
cause increased formation damage near the fracture face.
• The importance of an effective in-solution breaker system
is readily evident when evaluating formation damage.
Improved cleanup of gels can be obtained in almost all
situations if a more complete breaking of the gel occurs
within the formation matrix. The dual-fluids approach
to fluid-loss control can help manage more efficient
break and cleanup.
89
FRACPAC COMPLETION SERVICES
• In fracturing applications, a greater degree of formation
damage can be tolerated than in gravel-pack applications.
In most cases, production simulator results have indicated
that good regained permeabilities (in excess of 15%) will
provide excellent results. This observation favors the
borate-crosslinked fluid systems in high-permeability
formations since they provide better fluid-loss control
combined with acceptable levels of formation damage.
Sandstone acidizing procedures are sometimes used before,
during, or after a gravel-pack treatment to help remove
mobile fines and speed the cleanup of the load fluid. In
some cases, formation conditions are not favorable for
acidizing due to poor consolidation or incompatibilities
with the fluids being pumped. Concerns about formation
stability and compatibility should be addressed before
completing the job.
FRACTURE CONDUCTIVITY
REFERENCES
Fracture conductivity testing was performed with the same
selected fracturing fluids and core types and at the same
temperatures as the fluid-loss and formation-damage tests.
The results of fracture conductivity testing are listed in
Table 9.4.
1.
Parker, M.A., Vitthal S., McGowen, J., Martch, E., Rahimi, A.:
“Stimulation of High-Permeability Formations to Overcome
Formation Damage,” Paper SPE 27378, 1994 Annual Symposium
on Formation Damage,” Lafayette, Louisiana, February.
2.
McGowen, J.M., Vitthal, S., Parker, M.A., Rahimi, A., and Martch,
W.E. Jr.: “Fluid Selection for High-Permeability Formations, “ Paper
SPE 26559, 1993 SPE Annual Technical Conference, Houston,
Texas, October 3-6.
3.
Penberthy, W.L. Jr., and Shaughnessy, C.M.: Sand Control, SPE
Series on Special Topics, Volume 1, Richardson, Texas, (1992) 45-57.
4.
Schecter, R.S.: Oil Well Stimulation, Prentice-Hall, New Jersey
(1992) 365-370, 571-573.
5.
Harms, W.M.: “Application of Chemistry in Oil and Gas Well
Fracturing,” Oilfield Chemistry, Borchardt, J.K., and Yen, T.F. (eds.),
American Chemical Society, Washington, D.C. (1989) 55-101.
6.
Ely, J.W.: “Fracturing Fluids and Additives,” Recent Advances in
Hydraulic Fracturing, Gidley, J.L., Holditch, S.A., Nierode, D.E., and
Veatch, R.W. Jr. (eds.) SPE Monograph Volume 12 (1989) 131-146.
7.
Gulbis, J.: “Fracturing Fluid Chemistry,” Economides, M.J., and
Nolte, K.G.: Reservoir Stimulation, Prentice Hall, New Jersey (1989)
4-1 - 4-14.
8.
Sparlin, D.D., and Copeland, T.: “Pressure Packing with Concentrated
Gravel Slurry,” Paper SPE 4033, 1972 SPE Annual Technical
Conference, San Antonio, Texas.
9.
Sparlin, D.D.: “Sand and Gravel: A Study of Their Permeabilities,”
Paper SPE 4772, 1974 SPE Symposium on Formation Damage
Control, New Orleans, Louisiana.
HEC gels provided the best overall fracture conductivity.
The results of this testing are somewhat conservative since
the same fluids and in-solution breaker systems from the
fluid-loss tests and the formation-damage tests were used.
No delayed or encapsulated breakers were mixed with the
proppant. Had these breakers been used, the performance
of the crosslinked gels would have been greatly increased,
resulting in better fracture conductivity.
The fracture conductivity tests did show that under most
conditions, the HEC and the borate-crosslinked gels
outperformed all other fluids. When silica flour was used
as a fluid-loss additive, it caused significant reductions in
fracture conductivity.
GRAVEL-PACK COMPLETIONS
Gravel packing is slightly different from FracPac completions since it does not involve tip-screenout fracturing.
Gravel packing does, however, involve the near-wellbore
region of the well and thus gravel-pack fluids must be
kept very clean. All brines used in gravel-packing
procedures should be filtered before being injected into
the well. Gelled fluids should be sheared and filtered to
remove any microgels that could damage the formation
or the gravel-pack media.
Formation damage is a primary concern in gravel-pack
completions. To prevent formation damage, HEC,
biopolymers, or clean brines are the preferred fluids for
most gravel-pack completions. If heavy brines are required
for well control, special gelling considerations are required
to ensure adequate viscosity and stability. Specialty products
are available for such applications.
90
10.
Scheuerman, R.F.: “Guidelines for Using HEC Polymers for
Viscosifying Solids-Free Completion and Workover Brines,” JPT
(February 1983) 306-314.
11.
Scheuerman, R.F.: “A New Look at Gravel-Pack Carrier Fluid,”
SPEPE (January 1986) 9-16.
12.
Torrest, R.S.: “The Flow of Viscous Polymer Solutions for Gravel
Packing Through Porous Media,” Paper SPE 11010, 1982 SPE
Annual Technical Conference, New Orleans, Louisiana.
13.
Chauveteau, G., and Kohler, N.:” Influence of Microgels in
Polysaccharide Solutions on their Flow Behavior Through Porous
Media,” SPEJ, (1984) 361-368.
14.
Cole, C., Shah, S., Caveny, B., and Bellenger, B.: “Monitoring
HEC Gel Shearing to Optimize Improvements,” Paper SPE 17480,
1988 SPE California Regional Meeting, Long Beach, California.
15.
Houchin, L.R., Hudson, L.W., Caothien, S. et al.: “Reducing
Formation Damage through Two-Stage Polymer Filtration,”
Paper SPE 15408, 1986 SPE Annual Technical Conference,
New Orleans, Louisiana.
16.
Ashton, J.P., and Nix, C.A.: “Polymer Shear Mixer: A Device to
Improving the Quality of Polymer Viscosified Brines,” Paper SPE
14829, 1986 SPE Symposium on Formation Damage Control,
Lafayette, Louisiana.
17.
Penny, G.S.: “An Evaluation of the Effects of Environmental
Conditions and Fracturing Fluids Upon the Long-Term
Conductivity of Proppants,” Paper SPE 16900, 1987 SPE Annual
Technical Conference, Dallas, Texas.
18.
Parker, M.A., and McDaniel, B.W.: “Fracturing Treatment Design
Improved by Conductivity Measurements Under In-Situ Conditions,”
Paper SPE 16901, 1987 SPE Annual Technical Conference,
Dallas, Texas.
19.
Parker, M.A.: “Effect of Gelled Fracturing Fluids on the
Conductivity of Propped Fractures,” Paper CIM/SPE90-92, 1990
CIM/SPE Technical Conference, Calgary, Alberta.
20.
Norman, L.R., Hollenbeak, K.H., and Harris, P.C.: “Fracture
Conductivity Impairment Removal,” Paper SPE 19732, 1989 SPE
Annual Technical Conference, San Antonio, Texas.
21.
McGowen, J.M., and McDaniel, B.W.: “The Effects of Fluid
Preconditioning and Test Cell Design on the Measurement of
Dynamic Fluid Loss Data,” Paper SPE 18212, 1988 SPE Annual
Technical Conference, Houston, Texas.
22.
Cooke, C.E., Jr.: “Effects of Fracturing Fluids on Fracturing
Conductivity,” JPT, (October, 1975) 1273-1282.
23.
Almond, S.W., and Bland, W.E.: “The Effects of Break Mechanism
on Gelling Agent Residue and Flow Impairment in 20/40 Mesh
Sand,” Paper SPE 12485, Formation Damage Control Symposium,
Bakersfield, California, February 13-14, 1984.
24.
Harris, P.C.: “Chemistry and Rheology of Borate-Crosslinked
Fluids at Temperatures to 300°F,” JPT (March 1993) 264-269.
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FRACPAC COMPLETION SERVICES
APPENDIX A
where V is filtrate volume per area (m3/m2), v is filtrate
velocity (m/s), n ′ is flow behavior index (dimensionless),
and K ′ is consistency index (lbf-secn ′/ft2).
FLUID LOSS MODELS
The shear rate for a power law fluid inside a porous
medium is given by the equation
4v
.
. . . . . . . . . . . . . . . . . . . . . . . . . . . (9.1)
15)k
(8
10
For n = 1, i.e., a Newtonian fluid, the two previous
equations reduce to the classic equation for viscous fluid
leakoff that is used in most simulators:
VCv t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (9.5)
The wall shear stress for a fluid is given by
where
p
2L
(81015)k
. . . . . . . . . . . . . . . . . . . . . . . (9.2)
.
where is shear rate inside the core (sec -1), is superficial
filtrate velocity (m/sec), is rock factor (dimensionless),
k is core permeability (md), is core porosity (fraction),
is shear stress inside the core (psi), p is differential
pressure (psi), and L is core length (m).
The two previous equations, along with Darcy’s law, can
be used to determine the leakoff volume or rate behavior
versus time for a power law fluid. The filtrate volume and
rate are given by the following equations:
NOMENCLATURE
.
= shear rate inside the core (sec-1)
= superficial filtrate velocity (m/sec)
= rock factor (dimensionless)
= core porosity (fraction)
p = differential pressure (psi)
n′
81015k
n′ + 1
. . . . . . . . . . . . . . . . . . . . . . . . (9.3)
60t
k = core permeability (md)
K ′ = consistency index (lbf -secn′/ft2)
L = core length (m)
and
n′
v n′1
n′
1
n′1
72
p n′ + 1 n′ + 1
3n′1
K ′
81015k
60t
92
k p
. . . . . . . . . . . . . . . . . . . . . . . . . . (9.6)
fl
= shear stress inside the core (psi)
n′
1
n′1
72
p n′ + 1 n′ + 1
V 3n′1
K ′
Cv 0.04469
n′
n′ + 1
n ′ = flow behavior index (dimensionless)
V = filtrate volume per area (m3/m2)
v = filtrate velocity (m/s)
. . . . . . . . . . . . . . . . . . . . (9.4)
APPENDIX B
QUALITY ASSURANCE OF FRACTURING
FLUID SYSTEMS
Four check points exist for ensuring and maintaining the
quality of fracturing fluids used in stimulation treatments:
• Halliburton Duncan Technology Center
As companies within the oil industry are challenged to
operate with increasing financial concerns and narrower
profit margins, they have become very aware of the
cumulative impact of each step in the oilfield-development
process. A natural extension of the impact of operating
costs is the constant effort to improve quality.
• The field laboratory
To support our commitment to quality, Halliburton has
initiated a comprehensive, interactive quality program with
our vendors to ensure that the products we provide our
customers perform as designed. Product conformance
criteria, measurement parameters, and testing procedures
have been defined for fracturing-fluid additives as part of
a performance-tracking system.
Halliburton Duncan Technology Center
By installing point-of-source controls, the burden of routine
quality control testing is removed from the field engineers
and placed where it is most effective− at the vendor’s manufacturing facility. However, total quality management
does not end with vendor testing. Vendors are required to
submit samples to the Halliburton Duncan Technology
Center, where comprehensive testing is conducted on
random samples.
As in most mature industries, technological advances in the
petroleum industry proceed in incremental steps and not
in the giant leaps associated with emerging technologies.
The importance of incremental advances, however, should
not be overlooked. These small advances have accumulated
and resulted in production gains from wells that in the past
would not have been drilled because the technology to safely
complete the well did not exist, or the well would have
been abandoned because of poor economic performance.
Incremental advances have occurred in every discipline
within the petroleum industry, from the techniques and
equipment used to locate and extract hydrocarbons to the
methods used to increase production and maximize
recoverable reserves. Of all areas that undergo incremental
technological advances, quality control offers the greatest
potential for a positive financial impact on the viability
of a well.
• The jobsite
• Vendor facilities
Quality programs that are implemented between the
manufacturer and Halliburton Duncan Technology Center
ensure that the chemical and the performance criteria of a
product conform to established standards. This quality
program helps ensure that the products delivered to a
field camp perform as designed, with minimum variance
between lots.
Halliburton Technology is responsible for molding the
unique features and requirements of each quality check
point into a unified quality program. The Technology
Center is the center of criteria development, conformance
testing, and conformance tracking of fracturing additives.
The three other check points (the field lab, jobsite, and
vendors) perform specific tasks and are extensions of the
Technology Center.
The Field Laboratory
The field laboratory is responsible for random functional
testing of field samples to help ensure that they are
performing as required. Job-specific testing and system
optimization are performed by the field laboratory and are
based on local field conditions. Pre-job planning is performed by the field laboratory. In short, the field laboratory
supplies support and local expertise to field operations.
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FRACPAC COMPLETION SERVICES
The Jobsite
After comprehensive testing at the field laboratory, testing
at the jobsite is still performed to confirm fluid properties
and characteristics. The fluid system’s properties should
be determined and verified before any equipment arrives
on location. If major discrepancies are discovered between
field lab results and the results obtained at the jobsite, the
problems are evaluated more closely. Assistance from the
field lab should be sought with jobsite testing. Attempts
to fine tune or radically modify treatment schedules based
on onsite test results during the treatment can cause gross
errors. The small treatment volumes and relatively high
percentage of measurement error associated with the
equipment used to add components can magnify even
small adjustments.
Vendors
Halliburton works very closely with vendors of all products
to ensure that quality conditions are fulfilled at all times.
QUALITY ASSURANCE GUIDELINES
Before arriving on location, qualified personnel should
complete the following tasks.
1. Clean the fracturing tanks.
2. Add biocide to the first load of water as it is
transferred to the fracturing tank. Obtain a sample
of the water from each tank.
3. Analyze the dissolved and suspended components in
the water samples taken from the fracturing tanks.
4. Perform a bacteria count on the water samples.
5. Establish the base gel viscosity and pH.
6. Establish crosslink time control and make any
necessary adjustments.
7. Perform break tests to determine the breaker package
required to yield the desired break profile.
8. Test all proppants according to API RP 56 or
API RP 60.
IMPORTANT: Using the proper sampling technique is
critical to the outcome of the tests listed previously.
94
After arriving at the jobsite, qualified personnel should
perform the following tasks.
1.
Inspect the fracturing tanks and their contents for
gross abnormalities.
2.
Measure base-gel viscosity and pH and adjust as
required.
3.
Confirm that crosslink time is adequate and that a
suitable crosslink is formed.
4.
Confirm that fluid additives have been added.
5.
Confirm fluid break on wells with BHST below 200°F.
After the chemistry of the fluid system has been confirmed
at the field lab and at the jobsite, a successful fracture
stimulation then becomes operation-dependent.
IMPORTANT: Historically, fluid stability has shown
little dependency on the water source if the base gel’s
viscosity, pH, crosslinker concentration, and gel stabilizer
concentration are within accepted criteria limits. This
indicates that specialty testing (such as with a Fann
Model 50 viscometer) is not necessary on routine
treatments if the quality of the water source is known.
Checklist for Ballouts and
Fracturing Jobs
____ Ambient temperature and fluid temperature have
been measured and recorded.
To promote job safety and quality, make sure that the
following procedures and equipment preparations have
been completed.
____ The fluid system has been successfully pilot-tested
with the gel.
Fluids and Additives
Tanks
____ Tanks are clean inside and outside.
____ Fluid quality control and break tests were
completed before the job.
____ Internal coatings of the tanks are perfect. If not,
the tanks should be returned.
____ Necessary supplies of the proper additives are
available on location.
____ All valves are operable, leak-free, and are fitted
with proper opening and closing devices.
____ The method of injecting each additive has been
documented, and the operators in charge of the
process have been identified.
____ Tops of the tanks are skid-proofed (or are not
slippery), and all hatches open fully.
____ Tanks are positioned level or leaning forward.
____ All ladders are secured.
____ Depth to the shelf above the wheels and the depth
to the bottom of the tank has been gauged. Also,
check the condition of the gauge line.
____ The suction manifold and its valves, rubber hoses,
and unions are in good condition. The manifold is
properly fitted with valves. Measure the height of
the suction line above the bottom of the tank.
____ Methods of measuring the additive rate and the
discharged amounts of fluid have been
documented, and the operators in charge of the
process have been identified.
____ Pumps are operating properly. (Check the
condition of fluid transfer and the condition
of additive pumps.)
____ Diesel tanks are full, and hoses and valve clamps
are installed and in good condition.
____ Biocide has been added with the first load of water.
____ Diesel discharging equipment and measuring
devices have been identified, located, and
checked for proper operation. The measuring
devices should be accessible for quick repair.
Mix Fluid
____ Measuring gauges are monitored constantly to
track the volume of diesel used.
____ The source of the mixing fluid has been confirmed
and tested.
____ Fluid-transport trucks are perfectly clean and
committed to only the current job.
____ Tanks have been checked after the job to ensure
that any remaining fluid has been removed or
handled according to the customer’s wishes.
____ The amount of fluid hauled matches the amount
charged to the customer.
____ The fluid is clean, fresh, and free of foul odors and
discoloration.
____ The pH, bacterial content, specific gravity, and other
measurement points are within quality standards.
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FRACPAC COMPLETION SERVICES
Water Analysis
A high-quality fracturing fluid is an essential element of a
successful fracturing job. Water analysis allows the detection
of any components that may jeopardize the quality of the
fracturing fluid.
Fracturing Tanks
Fracturing tanks must be kept clean and be functioning
properly. The tanks should be steam cleaned and flushed
with clean, fresh water before arriving at the jobsite.
Residual gels, breakers, acids, rust, and various types of
organic matter can cause or carry contamination. Contamination interferes with hydration and crosslinking and
can result in high-temperature fluid instability, premature
failure, or both.
Fracturing tanks should be in sound mechanical condition,
leak-free, and fitted with valves and manifolds that operate
properly. Properly operating tanks and peripheral equipment
help ensure that control over mix concentrations, personnel
safety, and environmental compliance are all maintained. All
fracturing tank tops should be coated with non-slip material
and all ladders should be attached securely to the tanks.
When a fracturing tank is emptied, 10 to 20 bbl of
fracturing fluid may remain in the bottom of the tank.
To reduce this volume, elevate the rear of the fracturing
tank to allow the fluid at the bottom of the tank to flow
toward the manifold. Locate the fracturing tank higher in
elevation from the blender, and restrict the length of the
inlet hoses to less than 50 feet. Short hose lengths will
reduce the likelihood of the blender losing prime, which
could force a shutdown of equipment and jeopardize the
success of the treatment.
Water Quality
Source water should be tested for quality and rated
acceptable before it is used to mix a fracturing fluid.
Analysis of the source water should be performed to detect
components within the water that may alter fracturing
fluid qualities. The degree of alteration depends on several
qualities that follow:
• Fluid system
• Concentration of the contaminant
• Expected treatment temperature
96
• Contact time between the contaminant and the
fluid system
• pH of the fluid system
Because of the many factors that can affect fluid quality,
it is not always possible to set a specific limit on each
individual factor within the fluid system. Source water
should be pilot-tested before using it in a fluid system.
IMPORTANT: The subsequent maximum concentrations and temperature limitations are guidelines.
They are not intended to replace sound chemical or
engineering principles.
Iron (< 20 ppm)
Dissolved iron exists in two valence states in water: ferric
iron (Fe+3) and ferrous iron (Fe+2). Ferric iron will start to
precipitate as ferric hydroxide at pH 2.0 and is completely
precipitated at pH 3.5. For waters with a pH higher than
3.5, any ferric iron present is in the form of ferric oxide
(rust). As a solid material, ferric iron has minimal effect
on fracturing fluid properties. Ferrous iron is soluble in
waters with a pH of up to 7.5. This form of iron can alter
the valence states of metallic crosslinkers in fracturing
fluids, or act as a catalyst for oxidizing polysaccharide
gelling agents. Excessive amounts of ferrous iron can cause
a fracturing fluid to over-crosslink or to lose stability and
shear stability, or both. Excessive amounts of iron are
usually introduced to fracturing fluids by contact with rusty
fracturing tanks or transport tanks. Ferrous iron does not
begin to precipitate until the fluid reaches pH > 7.5. Some
fracturing fluids are incompatible with source waters that
contain as little as 8 ppm of iron.
Phosphates (< 5 ppm)
Phosphates are strong sequestering agents for metals, and
they will interfere with crosslinking. A sufficient concentration of phosphate can prevent crosslinking completely.
If phosphates exist in the source water, the dosage of
crosslinker may have to be increased to overcome the
effects of the phosphates.
Bicarbonates (< 1,000 ppm)
Zirconate crosslinkers require bicarbonate ion for proper
control of reaction kinetics; however, excessive bicarbonate
levels can be detrimental. Bicarbonates in concentrations
greater than 1,000 ppm can delay the crosslink for some
Table 9.1B — Source Water Guidelines
Iron
20 ppm
Phosphates
5 ppm
Bicarbonates
1,000 ppm
Reducing agents
0 ppm
Calcium and magnesium
2,000 ppm
Specific gravity
1.038
pH
6.0 to 8.0
Temperature
40°F to 100°F
Bacteria
105/mL
fluids. This can usually be overcome in some fluid systems
by adjusting the pH with hydrochloric acid (HCl).
Whenever possible, source water should be evaluated and
recommended based upon a preferred bicarbonate level
less than 500 ppm to avoid pH adjustments with acid.
prevent a gelling agent from fully uncoiling and hydrating.
A partially hydrated gel can be unstable. For best results,
use a source water that closely matches the characteristics
of fresh water.
Solids
Reducing Agents (0 ppm)
Contaminants such as bisulfite can prevent proper gel
hydration, cause premature crosslinking, or neutralize
oxidizing breakers. They can also alter the valence state of
metal ions. To overcome such problems, add a small volume
of oxidizer such as ammonium or sodium persulfate.
Solids are often a source of bacteria. They can cause
emulsions to form and stabilize, and may cause damage
to the proppant pack and permeability. Solids can be
removed by filtration.
pH
Hardness
(Calcium and Magnesium < 2,000 ppm)
Waters that contain excessive concentrations of calcium
and magnesium may exhibit problems with gelling,
crosslinking, and maintaining temperature and shear
stabilities. Adjust the pH with sodium hydroxide (NaOH).
Most polymer gelling agents will adequately disperse and
hydrate if the mix water has a pH of 6.0 to 8.0. A mix water
with a pH greater that 8.0 may result in a slow or poorly
hydrated gel. A mix water with pH of less that 6.0 can
hydrate rapidly and yield gel balls, lumps, or “fisheyes”
in the gel.
Temperature (40°F to 100°F)
Sulfates
Some crosslinkers may be precipitated by sulfate ion in
solution. Sometimes increasing the crosslinker dosage will
overcome this problem.
Specific Gravity
Specific gravity is an indicator of the degree of dissolved
salts in a fluid. Excessive levels of dissolved salts can
As the temperature of the mix water increases, the gelling
agent’s rate of hydration accelerates. At temperatures
approaching or exceeding 100°F, the rate of hydration may
cause gel balls, lumps, or fisheyes to form. Adding the gel
as a liquid gel concentrate (LGC) can ease dispersion
problems and reduce the possibility of fisheyes forming.
The pH of the source water can also be adjusted to retard
the hydration rate of the gelling agent. At mix-water
temperatures below 40°F, long hydration times may be
experienced and it may be necessary to heat the mix water.
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FRACPAC COMPLETION SERVICES
Table 9.2B — Effect of Bacteria on Base Fracturing Gel
Bacteria Count
Days before catastrophic viscosity
degradation of the base gel will occur
104
3 days
105
2 days
106
less than 1 day
Adding Biocide to Mix Water
Bacteria are capable of ingesting polysaccharide gelling
agents as a food source, and by doing so can double their
population in 20 minutes. Many bacteria found in mix
water can cause formation damage and hydrogen sulfide gas
production. Typical symptoms of bacterial contamination
are the following:
• Black gel
• Foul, putrid odor of fluid
• A change in gel pH in combination with a
lowering viscosity
To prevent problems associated with bacteria growth, add
biocide to the fracturing tank with the first load of water.
Follow the manufacturer’s recommendation for dosage.
Bacterial growth is the greatest at temperatures between
80°F and 100°F, and a pH from 4.0 to 8.0. It is important
to treat the source water before the bacteria population has
the opportunity to produce a significant level of enzyme,
which can remain active even after the bacteria has been
killed. On jobs where the gel has been mixed and a delay
occurs, the gelled fluid can be preserved by increasing its
pH to at least 11.0. Raising the pH will kill any remaining
bacteria and help denature any enzymes in the fluid.
The effects of bacteria on base-gel degradation are shown
in Table 9.2B.
• Delayed or incomplete crosslink
IMPORTANT: Make sure that the pH is lowered to the
proper level for fluid performance before starting the job.
98
Chapter 10
INTRODUCTION
Proppant selection is very important to
the success of completion and
stimulation operations, especially in
semiconsolidated formations. Achieving
good sand control and obtaining
maximum well productivity are
primary treatment goals that must be
considered when selecting proppants
for a FracPac job.
SAND CONTROL
To achieve good sand control, the many
variables that characterize sand production and migration must be studied.
These include formation damage depth,
production rates, drawdown pressures,
critical flow rate, formation mechanical
properties, proppant size, and formation
sand size distribution. Once these are
understood, a method can be selected
for controlling sand. The methods
involve the use of mechanical devices,
gravel packing, hydraulic fracturing,
and resin-related products.
Mechanical devices, such as wirewrapped screens, prepacked screens, and
slotted liners, can stop the movement
of formation sand into the wellbore.
Gravel packing–the placement of a
high-permeability proppant bed between
the wellbore and the formation–
further prevents fines migration to the
wellbore. In addition to proppants for
conventional gravel-packing jobs, lowdensity and steam-resistant gravels are
available for special applications. Table
10.1 lists some of the criteria that the
API recommends should be met by
gravel-pack proppants.1
Hydraulic fracturing can create highconductivity fractures that extend beyond
wellbore damage. This can significantly
reduce reservoir drawdown pressures,
decreasing the possibility of mechanical
formation damage during production. In
some cases, highly conductive fractures
can significantly increase the effective
wellbore radius, making it possible to
produce at higher rates without
exceeding critical fluid velocities in the
formation. Thus, this can also be an
effective means of sand control.
Proppant
Selection
Consolidated resin systems, such as
SANDFIX, HYDROFIX, and Eposand,
can be pumped into a formation to
provide formation consolidation and
stability. In fracturing applications in
which a screen will not be set later for
sand control, resin-coated proppants
can be used. Table 10.2 lists some
common resin-coated sands.
PRODUCTIVITY
Proppants are used in hydraulic
fracturing to provide a path for reservoir
fluids to flow into the wellbore. A
formation can be fractured to stimulate
production or to bypass damage around
the wellbore. In either case, proppants
must maintain conductivity under stress
after pumping pressure is removed and
closure stresses are applied at the fracture
faces. Therefore, strength is an important
property of proppants used in hydraulic
fracturing. Some of the proppant types
used in fracturing applications are
displayed in Table 10.3, with general
strength categories being indicated for
the uncoated manmade proppants.
Proppant size is also an important factor
in fracturing operations. Under most
conditions, large proppants have greater
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FRACPAC COMPLETION SERVICES
Table 10.1 — Recommended Criteria for Properties of Gravel-Pack Proppants
Recommended Criteria
Property
At most 0.1% by weight can be larger than the first sieve size.
Proppant size*
At least 96% by weight should pass the second sieve and be retained
on the sixth sieve.
At most 2% by weight can be smaller than the last designated sieve size.
Sphericity
0.6
Roundness
0.6
Acid-soluble materials
Turbidity
Clay and soft particle content
1% by weight
250 Formazin Turbidity Units
1% by volume
8% by weight for 8/16-mesh sand
Crush-Resistance Test
(% fines by weight)
4% by weight for 12/20-mesh sand
2% by weight for 16/30- and 20/40-mesh sand
2% by weight for 30/50- and 40/60-mesh sand
* For testing an M/N-mesh sand, six sieve sizes are used. The first sieve is slightly coarser than an M-mesh sieve, and the second
sieve is an M-mesh sieve. The third, fourth, and fifth sieves increase in fineness between (but not including) M-mesh and N-mesh.
The sixth sieve is an N-mesh sieve.
conductivity than small proppants. Table 10.4 indicates
the proppant sizes that are available for natural sands and
manmade proppants.
API guidelines for testing proppants used in fracturing
are found in two API publications: API RP 56: Testing
Sand Used in Hydraulic Fracturing Operations and API RP
60: Testing High Strength Proppants Used in Hydraulic
Fracturing Operations.2,3
PROPPANT SIZE
Depending upon the application, proppants can be selected
for complete sand control, maximum productivity, or a
balance between sand control and productivity.
Complete Sand Control
The goal in complete sand control is to prevent all formation sand from penetrating the gravel pack. All formation
sand, regardless of size ranges, must be stopped at the
interface between the formation and the pack. This may
require a very small proppant, which can result in lower
than normal fracture conductivity and well productivity.
However, it usually eliminates the production decline that
would otherwise result from invasion of formation fines.
100
Maximum Productivity
Since sanding tendency is usually not a major concern
when a treatment is designed primarily for maximum
productivity, the proppant size is selected that offers the
highest conductivity at the expected closure stress.
Balanced Sand Control and Productivity
To optimize sand control and productivity, the distribution
of pore throat size in the proppant bed and the distribution
of formation sand size must both be considered. The
proppant can be sized to allow the smaller formation
particles to pass through the proppant bed if they cause
only minimal damage to the bed’s conductivity and
permeability. Current practices indicate that the stresses
imposed on the fracture face during fracturing may help
prevent sand migration into the proppant bed. This is one
possible explanation for the success of larger proppants,
such as 20/40-mesh, which have displayed increased
conductivity, reduced drawdown, and, in most cases,
good sand control.
Table 10.2 — Common Resin-Coated Sands
Precoated
Coated On-The-Fly
Precured
Partially Cured
Curable
AcFrac PRB
AcFrac Ultra SB
AcFrac CR
PropLok 11
TEMPERED LC
AcFrac CR 5000
PropLok 12
TEMPERED DC
SUPER LC
PropLok 32
TEMPERED H
SUPER DC
PropLok 33
AcFrac PR-5000
SUPER HS
* Manmade proppants can be resin-coated on special order.
Table 10.3 — Proppants Used for Fracturing Applications
Class
Examples
Type
Ottawa sand
Brady sand
Natural Sands
Resin-coated sand
Low-quality sand
Intermediate-Strength Ceramics
EconoProp CarboLite
LWP Plus
Intermediate-Strength Bauxite
Carbo-Prop HC
INTERPROP PLUS
Manmade Proppants
High-Strength Bauxite
SUPERPROP
ULTRAPROP PLUS
High-strength bauxite
Resin-Coated Proppants
Any proppant
Table 10.4 — Proppant Sizes Available for Fracturing Applications
Mesh
Natural Sands
Manmade Proppants
12/20
✓
✓
✓
16/20
16/30
✓
20/40
✓
✓
40/70
✓
✓
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FRACPAC COMPLETION SERVICES
Table 10.5 — Proppant Selection Guide
Service
Proppant Sizing Criterion
Proppant Size
Screen Size
Gravel Pack
Formation sand size
distribution
5 times mean diameter
of formation sand
Maximum
FracPac
Balanced sand control
and conductivity
Between Gravel Pack
and OptiPac
Maximum
OptiPac
Balanced sand control
and conductivity
Select for maximum
conductivity
na
OptiFrac
Formation conductivity
Select for maximum
conductivity
na
Fracturing
Formation conductivity
Select for maximum
conductivity
na
PROPPANT SELECTION
RECOMMENDATIONS
• Quantification of critical flow rates and verification
with sand production models
There is some disagreement in the industry regarding the
selection of proppant size. Saucier and Penberthy independently found that the effective bridging of formation sand
and the prevention of its movement into the proppant pack
can be achieved at a gravel to median formation sand size
ratio of 5 to 6 or less.4,5
• Determination of formation mechanical properties
Leone claimed that Saucier and Penberthy did not use
proper formation sand materials in their studies.6 In those
studies, very little cementing material was available to
bond individual sand grains to one another in the washed
out sands that were used. By using the actual formation
core plugs and carcass material to simulate formation
materials, Leone found that effective sand control could
be obtained at a 16 to 1 ratio of mean gravel diameter to
mean formation sand diameter. He suggested that this
high ratio was due to the agglomerate forms of produced
formation sand consisting of two or more grains as opposed
to the individual grains that were produced in the Saucier
and Penberthy studies.
• Determination of proppant embedment tendencies in
soft formations
Oyeneyin et al. suggested that all the then-current sizing
formulas might be too general because they fail to consider
the formation sand environment and the operational
conditions.7 Oyeneyin et al. proposed a set of semiempirical equations to predict the bridging effectiveness of the
selected gravel under specified operational conditions.
Table 10.5 outlines a general proppant selection guide.
Halliburton recommends that, as part of the selection
process, important aspects of treatment design be studied
through experimental and numerical analyses. These
analyses include
102
• Determination of formation sand size distribution
• Characterization of the flow field around the gravel
pack and, if necessary, around a short fracture
REFERENCES
1 Recommended Practices for Testing Sand Used in Gravel-Packing
Operations (API RP 58), American Petroleum Institute,
Washington, D.C. (1986).
2 Recommended Practices for Testing Sand Used in Hydraulic
Fracturing Operations (API RP 56), American Petroleum Institute,
Washington, D.C. (1983).
3 Recommended Practices for Testing High Strength Proppants Used in
Hydraulic Fracturing Operations (API RP 60), American Petroleum
Institute, Washington, D.C. (1989).
4 Saucier, R.J.: “Considerations in Gravel-Pack Design,” JPT
(January 1974) 19-24.
5 Penberthy, W.L. Jr., and Cope, B.J.: “Design and Productivity of
Gravel-Packed Completions,” JPT (October 1980) 1679-1686.
6 Leone, J.A., Mana, M.L., and Parmley, J.P.: “Gravel-Sizing Criteria
for Sand Control and Productivity Optimization,” Paper SPE 20029,
SPE California Regional Meeting, Ventura, California, April 4-6, 1990.
7 Oyeneyin, M.B., et al.: “Optimum Gravel-Sizing for Effective Sand
Control,” Paper SPE 24801, 1992 SPE Annual Technical
Conference and Exhibition, Washington, D.C., October 4-7.
Chapter 11
INTRODUCTION
Proper selection and execution of a
perforating program is essential to the
success of a FracPac completion. Perforations are the fluid flow channels whereby
treatment fluids enter a formation and
produced fluids leave to flow up the
completion tubulars. Thus, perforation
characteristics can greatly affect induced
fractures and reservoir production.
This chapter discusses how perforation
characteristics influence fluid flow, what
factors must be considered in selecting
a perforating system, and how computer
programs are used to estimate downhole
perforator performance and resulting
wellbore flow parameters.
OPTIMIZING FLUID FLOW
The ultimate goal in perforating is to
establish effective fluid communication
between the wellbore and the reservoir.1
The perforating program should be
designed to remove or minimize any
impedances to the desired fluid
movement. Major factors that influence
fluid flow through perforations are
perforating geometry, damaged zones
around the wellbore, and crushed zones
around the perforations.
Terminology
Perforating geometry is one aspect of
perforating over which considerable
control can be exercised. As illustrated
in Figure 11.1, perforating geometry
includes gun phasing, shot density,
perforation diameter, and perforation
length. Varying the geometry can
produce significant variations in fluid
flow. The geometry that should be
selected for a particular job will be
determined by well conditions and the
type of perforating application.
One well condition that influences the
selection of perforating geometry is
formation damage caused by drilling
fluids. This occurs long before the well
is perforated and can result in decreased
permeability. When drilling fluids enter
the formation, they can deposit solid
matter, cause clay swelling, and induce
chemical precipitation, all of which
reduce the effective size of the pores
available for fluid flow. The affected
region about the wellbore is called the
damaged zone. A main objective in perforating is to penetrate beyond this zone.
Perforating
The perforating process itself can also
cause damage to the formation. The
radial displacement of formation
materials during the creation of the
perforation crushes and compacts the
region immediately surrounding the
perforation. The affected envelope
around the perforation is called the
crushed zone (Figure 11.2) and usually
exhibits reduced permeability, typically
on the order of 40 to 60% of the
permeability of the undamaged
formation. As measured from the wall
of the perforation tunnel, the depth
that crushed-zone damage extends into
the formation usually does not exceed
one perforation diameter. Another one
of the important goals in perforating is
to use equipment and techniques that
minimize perforating damage.
Reductions in fluid flow between the
borehole and formation are often
described in terms of skin effect, as
though skins or membranes are present
that restrict fluid movement. The terms
crushed-zone skin effect and damagedzone skin effect are commonly used
with this connotation.
103
FRACPAC COMPLETION SERVICES
Effects of Varying Perforating
Geometry
Mathematical models have been derived to study the
effects of perforating geometry on flow rates and to predict
downhole perforator performance. The next four figures
present the results of applying a mathematical model to
completion conditions that were identical, except that
one aspect of perforating geometry varied in each case.
For each factor in perforating geometry that varied, the
different relationships that arose between bottomhole
pressure and liquid flow rate were determined. Neither a
crushed zone nor a damaged zone was assumed to exist.
Gun
Phasing
Perforation
Diameter
Pentration
Shot
Density
Gun Phasing
Figure 11.1 — Perforating geometry involves gun phasing, shot
density, perforation diameter, and perforation length.
Casing
Cement
Undisturbed Formation
(Permeability ku)
Damaged Zone
(Permeability kd)
Crushed Zone
(Permeability kc)
Figure 11.2 — Drilling produces a damage zone around the
wellbore, and perforating creates a crushed zone around the
perforation. Permeability is less in both zones than in
undisturbed formation.
Gun phasing refers to the angular measurement between
adjacent perforations produced by a perforating gun, when
the perforations are projected to lie in a single plane
normal to the wellbore. Gun phasing can have a significant
effect on flow rates. In Figure 11.3, four phasings are
considered: 0˚ (which is equivalent to 360˚ and in which
all of the charges have the same vertical orientation), 180˚,
120˚, and 90˚. The figure indicates that the highest flow
rate is obtained with the smallest (nonzero) phase angle.
This is reasonable since the more uniformly shots are
distributed around the circumference of a wellbore, the
less interference there is between fluids flowing radially
toward the wellbore.
Shot Density
Shot density is the number of perforations placed over an
interval of unit length in the wellbore. It is usually expressed
in shots per foot (spf) or shots per meter (spm). The results
of Figure 11.4 show that the highest flow rate is obtained
with the highest shot density. Since 0˚ phasing is used
and since Figure 11.3 showed this to be the least effective
phasing, other phasings would be expected to yield higher
flow rates. High shot densities should be used in laminated
formations and in formations where there is significant
contrast between horizontal and vertical permeability.
Perforation Length
In Figure 11.5, the highest flow rate is obtained with the
longest perforation length. Since 0˚ phasing is used and
since Figure 11.3 showed this to be the least effective
phasing, other phasings would be expected to yield higher
flow rates. It should be noted that under actual well
conditions where a damaged zone does indeed exist, the
highest flow rates will be obtained when the perforation
104
Perforating Geometry Effects
Perforating Geometry Effects
Shot Density
Gun Phasing
5,000
90°
2,080
120° & 180°
2,060
0°
2,040
2,020
2,000
Flowing Bottomhole
Pressure (psig)
Flowing Bottomhole
Pressure (psig)
2,100
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed Zone
0.5 in.
7.0 in.
4 spf
Variable
None
None
4,000
0.5 in.
7.0 in.
Variable
0°
None
None
3,000
6 spf
2,000
4 spf
2 spf
1,000
1 spf
0
1,980
1,550
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed Zone
1,560
1,570 1,580 1,590
Liquid Rate (BLPD)
0
1,600
Figure 11.3 — The highest flow rates are obtained with
the smallest nonzero phase angle.
1,000
2,000
3,000
Liquid Rate (BLPD)
4,000
Figure 11.4 — The highest flow rates are obtained with the
largest shot density.
Perforating Geometry Effects
Perforation Length
3,500
Flowing Bottomhole
Pressure (psig)
tunnel extends beyond the damaged zone. The distance
that the perforation tunnel extends beyond the damaged
zone affects flow rates much more in low-permeability
zones than in high-permeability zones. It should also be
noted that the actual flow rate is a function not only of
perforating geometry, but also of damaged-zone radius,
damaged-zone permeability, formation permeability,
and borehole size.
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed Zone
3,000
0.5 in.
Variable
4 spf
0°
None
None
2,500
2,000
16 in.
8 in.
4 in.
2 in.
1,500
1,000
Perforation Diameter
Minimizing Crushed-Zone Skin Effect
It is important to minimize the crushed-zone damage. The
next three examples examine the influence of perforation
diameter, perforation length, and gun phasing on reducing
crushed-zone skin effect. Each example assumes a shot
density of 4 spf, no damaged zone, and an annular-shaped
crushed zone 0.5 inches thick around each perforation. The
crushed zone permeability is designated kc ; the permeability
of the undisturbed formation is designated ku.
1,200
1,400 1,600 1,800
Liquid Rate (BLPD)
2,000
Figure 11.5 — The highest flow rates are obtained with the
longest perforation length.
Perforating Geometry Effects
Perforation Diameter
4,000
Flowing Bottomhole
Pressure (psig)
Figure 11.6 demonstrates that the highest flow rate is
obtained with the largest perforation diameter. Since 0˚
phasing is used and since Figure 11.3 showed this to be the
least effective phasing, other phasings would be expected
to yield higher flow rates. Perforation entry hole diameter
is of prime importance in poorly consolidated formations
and in gravel-packing operations: large diameters are
important in ensuring that the pressure drop across the
perforation is kept to a minimum, thereby preventing
sand inflow into the well.
1,000
3,000
0.4 in.
2,000
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed Zone
Variable
7.0 in.
4 spf
0°
None
None
0.3 in.
0.2 in.
1,000
0.1 in.
0
0
500
1,000
1,500
Liquid Rate (BLPD)
2,000
Figure 11.6 — The highest flow rates are obtained with the
largest perforation diameter.
105
FRACPAC COMPLETION SERVICES
Minimizing Crushed-Zone Skin Effect
Varying Perforation Diameter
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed-Zone Thickness
1.1
Open Hole
1.0
Productivity Ratio
Variable
12 in.
4 spf
0°
None
0.5 in.
kc /ku = 1.0
0.4
0.9
0.2
0.8
0.1
0.7
0
0.25
Perforation Diameter (in.)
0.50
Figure 11.7 — Large-diameter perforations are more effective
than small-diameter perforations in overcoming crushed-zone
skin effect. (After Locke2)
Minimizing Crushed-Zone Skin Effect
Varying Perforation Length
Well Flow Efficiency
1.0
0.9
9 in.
0.7
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed-Zone Thickness
1.0
0
Figure 11.8 — Long perforations are more effective than short
perforations in overcoming crushed-zone skin effect. (After Locke2).
106
Figure 11.9 compares the permeability ratio and productivity ratio for 0˚ and 90˚ gun phasings. PR values are
clearly higher for the 90˚ phasing. Notice that PR begins
to decrease dramatically when the permeability ratio falls
below about 0.3.
Figure 11.10 compares PR values when a particular zone
has no damage, when it has invasion damage only, and when
it has both damage due to invasion and crushing due to
perforating. Damaged-zone thickness is assumed to be
8 inches; damaged-zone permeability is denoted kd . At any
particular point, vertical and horizontal permeabilities are
assumed to be equal.
0.5 in.
Variable
4 spf
0°
None
0.5 in.
0.5
Crushed-Zone Permeability
(kc /ku)
Formation Permeability
Figure 11.8 plots kc/ku versus well flow efficiency for two
penetration values. Well flow efficiency (WFE ) is the ratio
of the flow from an actual perforated completion to that
from an ideal perforated completion of identical geometry.
The figure indicates that the deeper penetration gives the
higher WFE values. Notice that when kc/ku drops below
about 0.3 for either penetration (i.e., crushed-zone permeability is about one-third of undamaged formation
permeability or less), WFE begins to decrease rapidly.
This is significant since kc/ku can be less than 0.3 when
perforations are not backflushed or cleaned up. So, no
matter how deep the penetration, clean perforations are
necessary for effective fluid communication between the
formation and the wellbore.
The Damaged Zone
18 in.
0.8
Figure 11.7 compares perforation diameter and productivity ratio for different values of kc/ku. Productivity ratio
(PR ) is the ratio of the production flow of a perforated
interval to the equivalent openhole flow potential of the
same interval. The openhole completion is assumed to
have the same properties as the completed well except
that its total skin effect is zero. For an ideal completion,
the PR would be unity (1.0). In Figure 11.7, for a given
value of kc/ku, larger perforation diameters yield larger PR
values. Thus, all other factors being equal, larger-diameter
perforation will be more effective in overcoming crushedzone damage and will permit a larger volume of fluid to
flow than will smaller-diameter perforations.
Curve A plots penetration versus PR when there is no
damage of either type. Curve B shows that when
perforation damage is introduced (kc/ku = 0.2), PR drops
by a significant amount. If both perforation damage
(kc/ku = 0.2) and invasion damage (kd /ku = 0.4) are
present, PR drops even more as shown by Curve D. In
each of these cases, shot density is 4 spf.
Comparison of curves A, B, and D shows that attaining a
PR of 0.8, when no damage is assumed, requires perforations with penetration less than 2 inches. Perforation
damage alone increases this to nearly 6 inches, while the
addition of invasion damage increases the required
penetration to more than 10 inches.
Minimizing Crushed-Zone Skin Effect
Varying Gun Phasing
1.3
90°
1.2
Productivity Ratio
Curves C, D, and E compare PR for shot densities of 2,
4, and 8 spf when both the damaged and the crushed
zones are present. As expected, PR increases as shot density
increases. It should be noted that when perforations extend
past the damaged zone, there is an increase in the rate at
which PR increases with increased penetration.
Thus, to overcome the effects of the damaged zone, high
shot densities and deep-penetrating charges should be used.
Formations that have different vertical and horizontal
permeabilities, that have low-permeability streaks, or that
contain laminated shale also require high shot densities
for effective fluid communication between the reservoir
and the completion tubulars.
1.1
0°
1.0
Open Hole
0.9
0.8
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Damaged Zone
Crushed-Zone Thickness
Differential Pressure
Flow through a perforation can be hindered not only by
the surrounding crushed zone but also by any debris that
might be in the perforation. Contaminants from wellbore
fluids and remnants from the charge liner and case can
remain in the perforation tunnel. Thus, clean fluids that
do not react with formation clays should be in the well
when perforating, and the perforating charges and gun
systems should be as debris-free as possible.
1.0
0
Productivity Ratios for Various
Damage Effects
1.2
Convergent Flow Plus
Crushed Zone, kc /ku = 0.2
1.0
Convergent
Flow Only
Shot
Density
4
8
A
0.8
4
4
2
0.6
B
0.4
C
Damaged-Zone Thickness = 8 in.
kd /ku = 0.4
kc /ku = 0.2
D
0.2
Perforating underbalanced promotes cleaner, betterflowing perforations. Formation pressure being greater
than wellbore pressure causes formation fluids to surge
back toward the wellbore. This surge immediately cleans
out charge debris from the perforation tunnel and removes
compacted rock from the crushed zone. Wellbore fluids
0.5
Crushed-Zone Permeability
(kc /ku)
Formation Permeability
Figure 11.9 — Radially dispersed perforations are more effective
than inline perforations in overcoming crushed-zone skin effect.
(After Locke2)
Productivity Ratio
The previous section illustrated how perforating geometry
can be used to overcome damaged and crushed-zone skin
effects. Differential pressure can also be used to reduce
crushed-zone skin and other impedances to fluid flow
through perforations. Differential pressure is wellbore
pressure minus formation pressure. A balanced condition
exists when differential pressure is zero, i.e., wellbore
pressure equals formation pressure. An underbalanced
condition exists when differential pressure is negative, i.e.,
wellbore pressure is less than formation pressure. Conditions
are overbalanced when differential pressure is positive, i.e.,
wellbore pressure exceeds formation pressure.
0.5 in.
18 in.
4 spf
Variable
None
0.5 in.
E
Gun Phasing 90°
0
0
2
4
6
8
10
Perforation Length (in.)
12
Figure 11.10 — Damaged-zone skin effect can be overcome by
using high shot densities and deep-penetrating charges. (After Bell3)
107
FRACPAC COMPLETION SERVICES
Berea Sandstone Target
Core Flow Efficiency (CFE)
0.8
0.7
0.6
CFE 0.7 to 0.8
at Standard Test
Pressure (200 psi)
Threshold Pressure
for Optimum Cleanup
(≈ 150 psi)
0.5
Underbalanced Pressure for Optimum Cleanup
0.4
API Berea Sandstone Target
0.3
0.2
0.1
10 25
50
100
Underbalanced Pressure (psi)
200
Figure 11.11 — Underbalanced perforating promotes
perforation cleanup. However, increases in cleanup become
smaller with increases in underbalance. (After Bell3)
do not rush into the perforation; thus, plugging due to
debris and formation damage due to incompatible
fluids are minimized.
Figure 11.11 compares underbalanced differentials with
core flow efficiency for a Berea sandstone target. Core flow
efficiency (CFE) is essentially the ratio kp/ku, where kp is
the permeability of the perforated core and ku is the
permeability of the unperforated core. CFE is 1.0 for a
clean, undamaged core and is 0.0 for a perforated core
that permits no flow. In Figure 11.11, CFE is about 0.1
after perforating and before cleanup. CFE increases with
increasing underbalance and levels off to about 0.7 at
approximately 200 psi underbalance. The tests used to
generate this data were performed with kerosene saturating
the pore spaces of the Berea cores. The tests thus indicate
the required underbalance needed when a slightly
compressible fluid occupies formation pore spaces.
The differential pressure at the time of perforating is
adjusted according to the application, the reservoir fluid
(liquid or gas), and the perforating system that is used. In
most applications, underbalanced perforating is desired
because of the associated cleanup advantages. However,
extreme-overbalance perforating, such as Halliburton’s
PerfStim service in which very high positive differentials
are applied, is becoming popular in some fracturing
operations. In PerfStim operations, the differential is
generally 20 to 40% above the pressure required to
fracture the formation.
108
Either wireline or tubing can be used to run perforating
guns downhole and position them across the zones to be
perforated. In wireline-conveyed operations performed in
casing, production equipment has usually not yet been
installed, and temporary pressure-control equipment is
attached to the wellhead. For safety reasons, a slight overbalance of 100 to 200 psi is typically employed in this case.
In tubing-conveyed operations and in through-tubing
wireline-conveyed operations, production equipment is
installed before perforating, and underbalances of 1,000 to
3,000 psi can be used. To avoid casing failure and packer
unseating, the design for underbalance jobs must take into
account casing collapse pressures and differential pressures
across packers and other tools in the completion string.
Tubing-conveyed systems are also used in extremeoverbalance perforating because the production pressure
equipment must be in place to contain the high wellhead
pressures that are involved. In these operations, nitrogen is
typically used to generate a wellbore pressure that is 1.2 to
1.5 times formation pore pressure. When the perforating
charges are detonated or when a shear plug later expends, the
compressed nitrogen produces an extreme pressure surge
through the perforations and formation. This surge
fractures the formation. After the initial surge, the
treatment is typically continued by pumping an additional
two tubing volumes of nitrogen with commingled sand
and/or acid. In unconsolidated formations, perforating
with extreme overbalance eliminates concerns about sand
flowing into the wellbore around the guns. In addition,
subsequent pumping with commingled sand and optional
resin serves to prepack the perforations.
PLANNING AN EFFECTIVE
PERFORATING JOB
The key to effective perforating is planning long before it
is time to perforate. This will ensure that the best equipment and techniques are selected. The characteristics of the
formation, the perforating method that will be used, the
hardware that will be in the well, and the well conditions
expected at the time of perforating must all be considered.
Formation Characteristics
Formation characteristics to be considered include depth,
lithology (sand, lime, dolomite), pore fluid (gas, oil, water),
and pressure. Additionally, other pertinent information
should be gathered such as porosity, permeability, formation compressive strength, fluid densities, watercut,
irreducible water saturation, and skin damage. Also, is the
zone fractured? Does it contain shale stringers? Is this a
recompletion of the formation? Has this same zone been
completed in a nearby well, and if so, what were the
formation characteristics, completion objectives, well
conditions, perforating equipment, perforating techniques,
and perforating results? All this information can begin to
indicate what type of gun, charge, and perforating method
should be used. However, completion objectives and well
conditions must be examined closely before a final
decision can be made.
Small
Cross
Section;
Large
Pressure
Drop
Low
Flow
Rate
Completion Types
Screen
Three completion types will be considered: natural
completions, completions requiring sand control, and
completions requiring stimulation. Natural completions
are discussed to emphasize the special requirements of
FracPac completions, which combine sand control and
stimulation.
The underlying goal in all perforating jobs is to establish
effective fluid communication between the formation and
the wellbore; however, the method used to achieve this is
heavily influenced by formation characteristics. Since the
order of importance of the perforating geometrical factors
(gun phasing, shot density, perforation length, and
perforation diameter) can be different for different
completion types, the completion type has a significant
bearing on which perforating system is selected.
Formation
Cement
Casing
Liner
Large
Cross
Section;
Small
Pressure
Drop
High
Flow
Rate
Figure 11.12 — Pressure drops across large-diameter
perforations are smaller than across small-diameter perforations.
With small pressure drops, there is less potential for sanding.
Natural Completion
Natural completions are those in which no stimulation or
sand control operations are required. The objective is to
maximize PR . The order of importance of the perforating
geometrical factors is usually considered to be
1. Shot density
2. Perforation length
3. Gun phasing
4. Perforation diameter
In natural completions, particular attention should be paid
to perforation length to ensure that perforations extend
beyond the damaged zone, where possible. As Figure 11.10
demonstrated, PR increases more rapidly as a function of
perforation length once the perforation tunnel extends
past the damaged zone into the higher-permeability
undisturbed formation.
Sand Control
The objective in sand control operations is to prevent the
formation from deteriorating around the perforation
tunnels. When such deterioration occurs, the resulting
materials block the perforation tunnels and can clog the
casing and tubing.
In unconsolidated formations, sanding can occur if there
is an appreciable pressure drop between the formation and
the wellbore, and the forces cementing the sand grains
together are thereby exceeded. Since this pressure drop is
inversely proportional to the perforating cross section, the
probability of sanding can be minimized by maximizing
the total perforated area available for fluid flow. This is
controlled primarily by perforation diameter and shot
density. The larger the perforation diameter and the
higher the shot density, the larger will be the perforated
area and, for a given production rate, the smaller will be
the velocity of the produced fluid. See Figure 11.12.
109
FRACPAC COMPLETION SERVICES
In formations requiring stimulation, the diameter and
distribution of the perforations are most important.
Perforation diameters and shot densities are selected to
control pressure drops across the perforations and thereby
minimize the demands placed on pumping equipment.
Formation
Ball Sealer
Perforation
Induced
Fracture
Hydraulically
Casing
Cement
Figure 11.13 — In stimulation operations, ball sealers stop flow
through the perforations that are first to accept the stimulation
fluid.
Gun phasing and orientation are also important factors.
When the direction of the principal stresses in the formation are known, perforation stability in poorly consolidated
reservoirs can be improved by using 180˚ phasing oriented
perpendicular to the least principal stress or in the direction
of the maximum stress.
Thus, the order of importance of the geometrical factors
for sand control is
1. Perforation diameter
2. Shot density
3. Gun phasing and orientation
4. Perforation length
If the formation to be stimulated is thick or contains
multiple zones with different reservoir conditions, limited
entry stimulation techniques may be used. These techniques
can require relatively large distances between the perforations, and the distances between adjacent perforations can
vary from one perforation pair to the next.
When limited entry techniques are not used, good vertical
distribution of the perforations is necessary to optimize the
vertical extent of the treatment. A shot density of 4 spf is
usually sufficient. The radial distribution of perforations
can also have a significant bearing on the effectiveness of
the treatment. In fracturing operations, for example, if
90˚ phasing is used instead of 0˚ phasing, then perforations
are more likely to align with the orientation of the natural
fractures and in accordance with stress variations in the
formations. The perforations thus provide a less tortuous
path for the fracturing fluid to enter the formation. If the
stress direction is known, then 180˚ phasing aligned with
the preferred fracture direction can significantly reduce
initiation and treating pressures by providing a direct path
to the fracture and eliminating near-wellbore tortuosity.
To ensure that fracturing occurs through as many perforations as possible, ball sealers (Figure 11.13) are sometimes
used to seal off those perforations that are first to accept
the fracturing fluid or acid. In this case, burr-free, round
entry holes of consistent size are needed.
So, for stimulation operations, the order of importance of
the geometrical factors for perforating is
1. Perforation diameter
2. Shot density
3. Gun phasing and orientation
4. Perforation length
Stimulation
Stimulation operations involve acidizing and hydraulic
fracturing. The objective is to increase the size and number
of paths by which fluid can flow from the formation to
the wellbore. Both operations–acidizing and fracturing–
require that large amounts of fluid be pumped under
high pressure into the formation.
110
So, coincidentally, the order of importance of the
perforating geometrical factors is identical for both
FracPac operations.
Table 11.1 — Typical Underbalanced Pressure Differentials for Perforation Cleanup
Underbalanced Differential
Underbalanced Differential
Formation Permeability
for Liquid Production
for Gas Production
High (100 md)
200 to 500 psi
1,000 to 2,000 psi
Low ( 100 md)
1,000 to 2,000 psi
2,000 to 5,000 psi
Well Conditions
Wellbore Fluids
Formation characteristics and completion objectives
determine the perforating geometrical factors needed in a
perforating system. Well conditions, on the other hand,
usually determine the size and type of gun that can be run,
which can also play a significant role in the effectiveness
of perforating operations.
Muds and dirty fluids can plug perforations, so clean
completion fluids should be used during perforating.
Special conditions may require selecting a completion
fluid to suppress clay swelling or to avoid the formation
of precipitates, either of which can block the passage of
fluids through the formation.
Well conditions that must be considered in a FracPac
perforating job include the type, size, and condition of
wellbore tubular goods and other hardware; the presence of
obstructions or corkscrews in tubular goods; any wellbore
deviations or doglegs; the quality of the cement bond
between casing and formation; and the type and level of
wellbore fluids. Total depth and bottomhole temperature
should also be noted. Attention must also be given to any
other conditions that could affect perforating operations.
For example, derrick height can restrict the maximum
through-tubing gun lengths that can be used.
If corrosive fluids, high temperatures, or high pressures
are likely to be encountered, then hollow-carrier guns are
preferred. These guns protect the charges and ensure
reliable operation under harsh conditions. High wellbore
temperatures require that special charges, detonators, and
detonating cord be used.
Wellbore Hardware
The size of the tubular goods and obstructions within them,
such as landings and nipples, determine the maximum
outside diameter (OD) of the gun that can be run. If there
are corkscrews in the tubing or if there are any sharp
deviations or doglegs in the well, then a wire or strip gun
would be selected instead of a hollow-carrier gun. If a perforator’s performance under actual downhole conditions is
to be estimated from API target data, then the well’s casing
size, grade, weight, and yield strength must be known.
If the tubular goods are in poor condition or if the cement
bond is of poor quality, then a hollow-carrier gun would
be desirable to protect the tubulars from any further
damage. If a hollow-carrier gun cannot be used when these
conditions are prevalent, then there should be liquid in
the borehole to cushion the tubulars from the shock of
the detonating charges.
Differential Pressure
Fluid level in the borehole can be adjusted to give the
differential pressure needed at the time of perforating. As
discussed earlier, underbalanced perforating can result in
cleaner perforations; however, excessively high underbalance is not generally recommended since it can result in
formation damage. As Figure 11.11 demonstrated, there
is a maximum underbalance above which little or no
cleanup occurs. Excessively high underbalance can cause
sanding or movement of fines and therefore can impede
instead of improve flow into and through perforations.
Table 11.1 gives underbalanced pressures recommended for
perforation cleanup. The values shown depend on formation
permeability and formation fluid. Low permeability zones
require higher differentials to force the liquid through the
formation pores. Gas zones also require higher differentials
since gas has a much higher compressibility than oil and
thus does not flow back as readily as oil after being
compressed during perforation.
111
FRACPAC COMPLETION SERVICES
Shale
For a new through-tubing completion, the tubular goods,
packers, and other downhole equipment are also selected to
allow passage of the largest diameter gun system possible.
The use of full-open tools or monobore-type completions
will allow the largest diameter perforating systems to be
run under controlled differential conditions.
On new wells, the casing program should call for a short
joint of casing (a pup joint) to be placed near the bottom
of the well (and below tubing, if tubing is to be run). This
will provide an easily identifiable marker on the casing
collar log needed to confirm the depth readings recorded
by the perforating unit.
Sand
In older wells, gun selection must usually be tailored to
existing borehole conditions. For example, there may be
liners run in damaged casing or there may be permanent
packers or tubular goods that cannot be changed without
major expense. Both of these conditions can place severe
restrictions on the size and type of gun that can be run.
Similarly, if the wellbore is already exposed to high-pressure
formations, perforating system selection may be limited and
additional pressure control equipment may be required.
Gun Selection
Figure 11.14 — A perforating system that allows individual gun
sections to be selectively fired is used to perforate widely separately
zones on one trip into the well. In the scene depicted here, intervals
A and B have already been perforated using the lower sections of
the gun, and the gun is positioned to perforate interval C.
New Wells Versus Older Wells
The freedom possible in gun selection depends heavily
upon whether the perforating operation involves a new
well or an older well. In the case of new wells, borehole
conditions can often be tailored to the type of gun that is
desired. For example, if FracPac operations are to be
undertaken on a new well, then casing can be selected to
allow the passage of the large-diameter hollow-carrier
casing guns that will give the desired high shot densities
and large entrance hole diameters.
112
Once formation characteristics, completion objectives, and
wellbore conditions have been examined, an intelligent
choice of perforating systems can be made. Table 11.2 lists
the major categories of perforating guns and gives the main
features and applications of each. Table 11.3 lists the
important physical characteristics of these guns. Special
assemblies are sometimes needed in FracPac and related
operations that involve multiple-zone completions,
squeeze cementing, and remedial work to establish flow
or circulation.
Perforating Multiple Zones
Hollow-carrier guns can be used to perforate multiple
zones during a single trip into the well. Special Select Fire
subassemblies placed between gun sections allow the
sections to be fired individually. For example, as illustrated
in Figure 11.14, the lowest section can be fired in one zone,
the gun moved up, and the next section fired in another
zone. If required by the application, the gun sections can
be phased differently and have different shot densities.
With strip and wire guns, multiple zones are perforated by
using blank gun sections between the zones to be completed
and then simultaneously firing all charges. Blank sections
are gun sections containing no charges. Blank sections are
not usually used with hollow-carrier guns.
Table 11.2 — Features and Applications of Hollow-Carrier Guns
ThroughCasing
Tubing
Gun
Gun
✓
✓
Features
Carrier protects charges from
borehole environment.
Applications
High-pressure wells
High-temperature wells
Wells containing corrosive fluids (H2S, CO2, acid)
✓
✓
Carrier protects casing and cement
from shock of charge detonation.
Zone to be perforated is near oil-water contact.
(minimizes possibility of water migration due to
casing or cement damage)
Well is to be fractured. (avoids casing splits that
would prevent ball sealers from seating)
✓
✓
Carrier retains debris from charge cases.
Zone to be perforated is near oil-water contact.
(minimizes possibility of water migration due to
casing or cement damage)
Well is to be fractured. (avoids casing splits that
would prevent ball sealers from seating)
✓
✓
Gamma perforator combination
is available.
Well has no correlation log available. (permits gamma
correlation logging and perforating to be done on
same trip in well)
✓
✓
Selective fire is available.
Wells with widely separated zones to be perforated
(requires fewer trips downhole to perforate)
✓
✓
Spiral-jet carriers are available.
Squeeze cementing (increases probability that
perforations intersect a channel)
Hydraulic fracturing (increases probability that
perforations intersect natural fractures)
✓
✓
High-shot-density carriers are available.
Gravel packing (reduces flow velocity through
perforations when large-entry-hole charges are used)
Sand control (prevents sanding when small-entry-hole
charges are used, but permits adequate fluid flow for
production when high perforation density is used)
Hard formations (increases flow rates when
large-entry-hole charges are used)
✓
Gun has small diameter.
High-pressure wells (Gun can pass through tubing.)
Table 11.3 — Features and Applications of Strip and Wire Guns
Strip
Wire
Gun
Gun
✓
✓
Features
Larger explosive load will pass through
small restriction.
Applications
Deep penetration is needed.
Large entrance hole diameter is needed.
✓
✓
Flexible carrier
Well has dogleg or corkscrewed tubing.
✓
✓
Light weight
Long intervals are to be perforated on
one run into well.
✓
✓
Economical carrier
Multiple zones are to be perforated. (Fewer trips
are required with the long carriers; no charges are
loaded over those carrier sections corresponding
to intervals that are not to be perforated.)
113
FRACPAC COMPLETION SERVICES
Squeezing and Fracturing
In some instances, a radial charge distribution denser than
that provided by guns phased 90˚ or less is desired. For
example, in hydraulically fracturing a naturally fractured
reservoir, a high radial distribution of shots increases the
chances of perforations intersecting natural fractures.
Similarly, in squeeze cementing to eliminate channels, a
high radial distribution of shots increases the chance of
perforations intersecting channels and thus of cement
being pumped into those channels.
Radial Distribution
of Perforations
When Spiral
Phasing is Used
Halliburton’s Spiral Jet perforating guns provide the high
radial shot density desired in these applications. These
hollow-carrier guns have an effective 15˚ phasing over 6
ft of perforated interval. So, as Figure 11.15 shows, over a
6-ft interval, perforations from these guns extend out
from the borehole in 24 directions.
Radial Distribution
of Perforations
When 90° Phasing
is Used
Perforating Tubing and Drillpipe
Figure 11.15 — Over a 6-ft interval, Spiral Jet perforating guns
have an effective phasing of 15˚ and perforate in 24 directions.
Perforations from a standard 90˚-phased gun extend out in only
4 directions.
Tubing Puncher charges use controlled penetration to
perforate tubing or drillpipe without damage to the
surrounding casing. Loaded in hollow-carrier throughtubing guns, these charges can be used to establish
circulation when drillpipe is stuck. They also allow tubing
or tailpipe below a packer to be perforated when the
original tubing or nipple has become plugged.
Additionally, tubing above a packer can be perforated to
circulate sand from the top of the packer.
Ensuring Proper Gun Clearance
Cement
Casing
Gun
Perforation
Figure 11.16 — Decentralization is desired in 0˚-phased guns
since this generally increases perforation length. However, for
guns that are not phased at 0˚, decentralization causes variations
in perforation length and diameter.
114
Proper clearance between the gun and the casing is
necessary to obtain optimal charge performance. Clearance
is associated with gun centralization or decentralization in
the borehole. Figure 11.16 illustrates how charge performance can vary with variations in clearance.
When hollow-carrier casing guns are run in the casing
size for which they are designed, no centralization or
decentralization is required since any variations in clearance
around the gun will be minimal. However, if a such a gun
is run in a casing size for which it was not designed, special
care must be taken to centralize the gun in the wellbore.
This ensures that perforation entry hole size and perforation
length are uniform around the wellbore. With hollowcarrier through-tubing guns, if there is an appreciable
difference between the gun’s OD and the casing’s inside
diameter, the guns should be 0˚ phased and decentralized
for maximum penetration and maximum entrance hole
diameter. Magnetic and mechanical gun decentralizers
are available for these guns.
CERTIFICATION DATA SHEET
PERFORATING SYSTEM EVALUATION, RP 43, SECTIONS 1 and 2
API FORM
Explosive Weight ___________
gm, _________
powder, Case Material ___________________
AVAILABLE TO ALL
22.7
RDX
STEEL
Service Company ______________________________________________________
Max. Temp, F ______
1 hr _______ 3 hr _______ 24 hr _______ 100 hr ______ ______ hr
4-1/2” THREADLESS GUN SYSTEM (TGS)
325
Gun OD & Trade Name _________________________________________________
Maximum Pressure Rating _____________
psi, Carrier Material _________________________
4” DP
4,000
STEEL
Charge Name _________________________________________________________
Shot Density Tested _____________________________________________________shots/ft
C4500039 Date of Manufacture _____________
7/11/92
4
Manufacturer Charge Part No. _____________
Recommended Minimum ID for Running _________________________________________in.
RETRIEVABLE/EXPENDABLE/NON-SCALLOPED
Gun Type ____________________________________________________________
Available Firing Mode _________________ Selective, ____________________ Simultaneous
90
Phasing Tested _______
degrees, firing Order X
_____ Top Down, _______ Bottom Up
Debris Weight ___________________ gm/charge, Debris ___________________ in.3/charge
N/A
Debris Description______________________________________________________
Remarks _____________________________________________________________________________________________________________________________________________
SECTION 1 – CONCRETE TARGET
7”
32
L80
AUGUST 21, 1992
Casing Data ____________
OD, Weight _______________
lb/ft, ________________
API Grade, Date of Concrete Test _____________________________________________________________
48”
6,277
42
Target Data ____________
OD, Briquet Compressive Strength _____________
psi, Age of Target ________________________________________________________________________
days
No. 7
No. 8
No. 9
No. 10
Shot No.
No. 2
No. 3
No. 4
No. 5
No. 6
No. 1
0
0.41
0
0.41
0.89
Clearance, in. ..............................................................................
0.89
0.41
0.41
0.89
0.41
Casing Hole Diameter, Short Axis, in. . .......................................
0.33
0.44
0.44
0.38
0.40
0.41
0.38
0.37
0.42
0.43
0.34
0.46
0.44
0.40
0.42
0.42
0.38
0.39
0.47
0.45
Casing Hole Diameter, Long Axis, in. .........................................
Average Casing Hole Diameter, in. .............................................
0.34
0.45
0.44
0.39
0.42
0.42
0.38
0.38
0.45
0.44
16.95
13.78
14.65
17.45
15.95
18.55
18.55
14.15
19.65
19.65
Total Depth, in. ............................................................................
Burr Height, in. ............................................................................
0.07
0.06
0.04
0.11
0.05
0.03
0.07
0.08
0.07
0.06
No.11
No.12
No.13
No.14
No.15
No.16
No.17
No.18
No.19
No.20
Average
Shot No.
ND
0.41
0.89
0.41 _____ _____ _____ _____ _____
0.**
Clearance, in. ..............................................................................
0
ND
0.41
0.46
0.42
0.40 _____ _____ _____ _____ _____
0.41
Casing Hole Diameter, Short Axis, in. ........................................
Casing Hole Diameter, Long Axis, in. .........................................
ND
0.43
0.47
0.42
0.44 _____ _____ _____ _____ _____
0.42
ND
0.42
0.47
0.42
0.42 _____ _____ _____ _____ _____
0.42
Average Casing Hole Diameter, in. .............................................
Total Depth, in. ...........................................................................
ND
15.65
19.15
14.05
16.85 _____ _____ _____ _____ _____
16.73
ND
0.04
0.03
0.08
0.03 _____ _____ _____ _____ _____
0.06
Burr Height, in. ...........................................................................
Remarks ____________________________________________________________________________________________________________________________________________________
SECTION 2 – BEREA SANDSTONE CORE TARGET
Berea Bulk Porosity, ________________ %
Date of Berea Test _________________ %
Shot No.
Faceplate Hole Diameter, Short Axis, in. .........................
Faceplate Hole Diameter, Long Axis, in. ..........................
Average Faceplate Hole Diameter, in. .............................
Total Depth, in. .................................................................
No. 1
______
______
______
______
No. 2
______
______
______
______
No. 3
______
______
______
______
No. 4
______
______
______
______
No. 5
______
______
______
______
No. 6
______
______
______
______
Average
______
______
______
______
CERTIFICATION
Type of Certification: [X] Self
[ ] Third Party
I certify that these tests were made according to the procedures as outlined in API RP 43: Recommended Practices for Evaluation of Well Perforators, Fifth Edition, January 1991. All of the equipment
used in these tests, such as the guns, jet charges, detonator cord, etc., was standard equipment with our company for use in the gun being tested, and was not changed in any manner for the test.
Furthermore, the equipment was chosen at random from stock and therefore will be substantially the same as the equipment which would be furnished to perforate a well for any operator.
______ CERTIFIED BY
X RECERTIFIED
(Company Officer)
EXPLOSIVES PRODUCTS MANAGER
(Title)
(Date)
HALLIBURTON
(Company)
2001 S. I-35 ALVARADO, TX. 76009
(Address)
Figure 11.17 — API data sheets give information for comparing the performance of
different charges and for planning perforating operations.
COMPUTER-ASSISTED
PERFORATING PLANNING
Computer programs are available for selecting the
perforating geometry that will give optimal flow
characteristics for a particular application.
Perforating Planner
Halliburton’s Perforating Planner uses API RP-43 data
from surface tests to predict perforator performance at
downhole conditions. The program can use the statistical
variations in charge performance that occurs in API data
to induce corresponding statistical variations in predicted
downhole performance. The mathematical model underlying the program accounts for such variables as casing
grade, multiple casing strings, gun-to-casing clearance,
gun eccentralization, casing eccentralization, wellbore
fluid density, cement compressive strength, formation
strength, and formation effective stress. The Perforating
Planner provides detailed analysis of clearance effects on
entrance hole diameters and penetration, and furnishes a
clear diagram of the perforating system’s shot pattern.
Figure 11.17 displays an API data sheet for a certain
perforating system, and Figure 11.18 shows the Perforating
Planner’s graphical representation of that data. Figure 11.19
depicts the downhole performance that the Perforating
115
FRACPAC COMPLETION SERVICES
Perforating Planner
API RP 43 Section 1 Test Data: Phase Diagram
Gun Description
Mfgr: Jet Research Center
Type: 4-1/2-in. threadless
Part No.: C4500039
Powder: 23 gm RDX
Phasing: 90°
Shot Density: 4 spf
Rotation: 90°
Position: Eccentered
Test Target
Casing OD: 7.000 in.
Casing Wt.: 32.00 lbm/ft
Casing Grade: L-80
Target Type: Concrete Briquette
Briquette Comp. Strength: 6,277 psi
Surface Test
Perf No. Penetration
(in.)
1
17.93
2
16.31
3
16.68
4
15.75
Avg
16.73
Diameter
(in.)
0.420
0.432
0.413
0.397
0.417
Figure 11.18 — Information from the API data sheet of Figure 11.17 was used in Halliburton’s
Perforating Planner to profile the perforator’s typical test performance. Results are shown here
and take into account the statistical variations in the data that were reported on the API sheet.
Perforating Planner
Downhole Gun Performance: Phase Diagram
Gun Description
Mfgr: Jet Research Center
Type: 4-1/2-in. threadless
Part No.: C4500039
Powder: 23 gm RDX
Phasing: 90°
Shot Density: 4 spf
Rotation: 270°
Position: Eccentered
Well Configuration
Casing OD: 7.000 in.
Casing Wt.: 32.00 lbm/ft
Casing Grade: J-55
Borehole: 8.500 in.
Fluid: 8 lbm/gal
Damage: 2.000 in.
Downhole Performance
Rock Type: Sandstone
Rock Comp. Strength: 1,323 psi
Rock Porosity: 30%
Perf No.
1
2
3
4
Avg
Penetration
(in.)
19.11
17.37
19.11
17.74
18.33
Diameter
(in.)
0.430
0.407
0.430
0.420
0.422
Figure 11.19 — The Perforating Planner also used the API data of Figure 11.17 to predict the
perforator’s downhole performance under stated wellbore and formation conditions. Results are
shown here. Statistical variations in API data were also considered as in the previous figure.
116
Perforating Planner
Downhole Gun Performance: Casing Hole Phase Diagram
Gun Description
Mfgr: Jet Research Center
Type: 4-1/2-in. threadless
Part No.: C4500039
Powder: 23 gm RDX
Phasing: 90°
Shot Density: 4 spf
Rotation: 270°
Position: Eccentered
Well Configuration
Casing OD: 7.000 in.
Casing Wt.: 32.00 lbm/ft
Casing Grade: J-55
Borehole: 8.500 in.
Fluid: 8 lbm/gal
Damage: 2.000 in.
Downhole Performance
Rock Type: Sandstone
Rock Comp. Strength: 1,323 psi
Rock Porosity: 30%
Perf No.
1
2
3
4
Avg
Diameter
(in.)
0.430
0.407
0.430
0.420
0.422
Figure 11.20 — This closeup view generated by the Perforating Planner emphasizes how gun
eccentralization affects perforation entrance hole geometry. The perforating system here is the
same as that in Figure 11.17, and the casing parameters are the same as those in Figure 11.19.
Planner calculates could be typically obtained from that
system under the specified borehole and formation
conditions. Note that the downhole penetrations are
significantly greater than the API target penetrations; this
is largely due to the difference in compressive strength
between the downhole formation and the API target. The
slight difference in entrance hole diameters between the
downhole performance and API target performance can
be attributed to differences in casing characteristics.
Figures 11.20 and 11.21 from the Perforating Planner
focus on gun phasing and the resulting shot pattern for
the same system. Figures 11.22 presents the Perforating
Planner’s analysis of perforation entrance hole diameter as
a function of clearance. Such information is particularly
important when stimulating using gels with high sand
concentrations. Figure 11.23 shows the similar analyses
of perforation penetration as a function of clearance.
Figure 11.24 is a Perforating Planning summary of
program inputs and outputs related to the downholeperformance predictions that were illustrated in Figures
11.19 through 11.23.
Well Evaluation Model
Halliburton’s Well Evaluation Model uses wellbore configuration, formation characteristics, reservoir parameters,
and results from the Perforating Planner to predict inflow
performance. In particular, the skins and associated pressure
drops resulting from perforation, drilling fluid invasion,
partial completion, well deviation, and gravel packing are
nodally analyzed to determine flow rates. Figures 11.25
and 11.26 present graphical results from the model;
Figures 11.27, 11.28, and 11.29 list alphanumeric program
inputs and outputs associated with Figures 11.25 and 11.26.
The following procedures are typically involved when
applying the Well Evaluation Model:
1. An initial selection of a perforating system is made,
based on the general perforating geometry criteria for
the FracPac completion under consideration.
2. The Perforating Planner is used to determine the
downhole performance of the perforator.
117
FRACPAC COMPLETION SERVICES
Perforating Planner
Casing Shot Pattern
0
6
Gun Description
Mfgr: Jet Research Center
Type: 4-1/2-in. threadless
Part No.: C4500039
Powder: 23 gm RDX
Phasing: 90°
Shot Density: 4 spf
Rotation: 270°
Position: Eccentered
8
Well Configuration
Casing OD: 7.000 in.
Vertical Distance (in.)
2
4
10
12
0
45
90
135 180 225 270
Horizontal Distance (°)
315
360
Figure 11.21 — The Perforating Planner produces a two-dimensional representation of the
perforating system’s shot pattern into the casing. The perforating system here is the same as that
in Figure 11.17, and the casing OD is the same as that in Figure 11.19.
Perforating Planner
Casing Hole Diameter Clearance Analysis
Casing Hole Diameter (in.)
0.50
Gun Description
Mfgr: Jet Research Center
Type: 4-1/2-in. threadless
Part No.: C4500039
Powder: 23 gm RDX
Phasing: 90°
Shot Density: 4 spf
Rotation: 90°
Position: Eccentered
0.45
Test Casing
Casing OD: 7.000 in.
Casing Wt.: 32.00 lbm/ft
Briquette Comp. Strength: 6,277 psi
0.40
Well Casing
Casing OD: 7.000 in.
Casing Wt.: 23.00 lbm/ft
0.35
Section 1 Test Data
Downhole Clearance
Average of Test Data
Downhole Configuration
Offset Angle: 270°
Gun Position: Eccentered
0.30
0.0
0.5
1.0
Clearance (in.)
1.5
2.0
Note:
All diameters are based on L-80 casing.
Figure 11.22 — This graph created by the Perforating Planner compares perforation entrance
hole diameter with gun clearance. The diameters corresponding to the two downhole clearances
are those that would be obtained if the perforating system were shot in the same grade of casing
as the test casing. The perforating system is the same as that in Figure 11.17.
118
Perforating Planner
Penetration Clearance Analysis
18
Gun Description
Mfgr: Jet Research Center
Type: 4-1/2-in. threadless
Part No.: C4500039
Powder: 23 gm RDX
Phasing: 90°
Shot Density: 4 spf
Rotation: 90°
Position: Eccentered
16
Test Casing
Casing OD: 7.000 in.
Casing Wt.: 32.00 lbm/ft
Briquette Comp. Strength: 6,277 psi
14
Well Casing
Casing OD: 7.000 in.
Casing Wt.: 23.00 lbm/ft
20
e
Total Target P netration (in.)
22
Section 1 Test Data
Downhole Clearance
Average of Test Data
12
0.0
0.5
1.0
Clearance (in.)
Downhole Configuration
Offset Angle: 270°
Gun Position: Eccentered
1.5
2.0
Figure 11.23 — This Perforating Planner graph shows the relationship between perforation
penetration and gun clearance. The penetrations corresponding to the two downhole clearances
are those that would be obtained if the perforating system were shot in the same grade of casing
as the test casing. The perforating system is the same as that in Figure 11.17.
3. In the Well Evaluation Model, the perforator’s
downhole performance is used along with wellbore
and reservoir characteristics to estimate bottomhole
flowing pressures for a suitable range of flow rates.
7. From the perforating systems analyzed, the one that
best suits overall job requirements for such parameters
as flow rates, pressure drops, and critical sanding
pressures is selected.
4. The Well Evaluation Model is applied to the results
from Step 2 to generate an Inflow Performance
Relationship (IPR) curve.
The Well Evaluation Model assists in designing a FracPac
job by allowing the completion engineer to identify
parameters such as completion interval, perforation geometry, tubular specifications, and gravel pack requirements
that will give the preferred flow characteristics. Pore
pressure and critical sanding pressure are determined from
Halliburton’s STRESS Analysis Module (See Chapter 6)
and are considered when selecting the various parameters
for the preferred flow.
5. For a given wellhead pressure, the Well Evaluation
Model is used to determine the intake pressures at
tubing bottom for various flow rates. These values are
included on the IPR chart as a Tubing Intake curve.
The intersection of the Tubing Intake and IPR curves
gives the estimated flow rate and bottomhole flowing
pressure for the completion with the given perforating
geometry and wellhead pressure.
6. Steps 1 through 5 are repeated with other perforators
that satisfy the general perforating geometry
requirements of the job.
With regard to gravel-packed, unstimulated completions,
knowledge of the critical value of drawdown pressure at
which sanding might occur is crucial, as is knowledge of
the pore pressure. With the Well Evaluation Model results,
the completion can be optimized to obtain maximum
production and to maintain pressures below critical values.
119
FRACPAC COMPLETION SERVICES
PERFORATING PLANNER DATA SUMMARY
Gun Identification
Service Company ...............................Jet Research Center, Inc.
Trade Name........................................4-1/2-inch Threadless Gun
Charge Name .....................................4-inch DP
Part Number.......................................C4500039
Gun Type ..............Retrievable/Expendable/Non-Scalloped
Gun Diameter .......4.500 in.
Explosive Weight ...22.7 g
Powder .................RDX
Well Configuration
Rock Type.................................................................Sandstone
Reservoir Pressure (psig)............................................2,999.0
Porosity (%)..............................................................30.0
Effective Stress (lbm/ft) .............................................2,000
Compressive Strength (psi) .......................................1,323
True Vertical Depth (ft) .............................................5,000
Drillbit Diameter (in.) ................................................8.500
Centralized Casing ...................................................Yes
Hole/Casing Standoff (in.).........................................0.750
Number of Casings...................................................1
Completion Fluid Density (ppg).................................8.00
Casing OD (in) ..........................................................7.000
Casing Weight (lbm/ft) .............................................23.000
Casing Grade ...........................................................J-55
Downhole Gun Configuration
Shot Density (spf) .....................................................4.0
Phasing (˚) ................................................................90
Gun Position ............................................................Eccentered
Charge Pattern.........................................................Spiral
Gun Rotation (˚) .......................................................270.0
Predicted Downhole Gun Performance
Plane
Clearance*
(in.)
Rock
Penetration
(in.)
Casing Hole Diameter
(in.)
Casing/
Cement
(in.)
Casing 1
Casing 2
Casing 3
1
0.793
19.108
0.430
na
na
1.103
2
0.000
17.370
0.407
na
na
1.067
3
0.793
19.108
0.430
na
na
1.103
4
1.866
17.743
0.420
na
na
1.067
18.332
0.422
Average
* Maximum clearance in API Section 1 Test is 1.5940 in.
Figure 11.24 — The Perforating Planner furnishes a report that identifies the gun system, describes the well
configuration, states the downhole gun configuration, and lists the predicted downhole performance of the gun.
120
Well Evaluation Model
Nodal Analysis
Well Evaluation Model
Nodal Analysis
Pressure Drop vs Liquid Flow Rate
Formation Pressure Drop
Pressure Drop (psi)
80
60
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Flowing Bottomhole Pressure
vs Liquid Flow Rate
Variable
7.0 in.
8 spf
45°
Perforation Pressure Drop
(0.5-in. perforation diameter)
40
20
4,000
Inflow Performance Relationship
(0.7-in. perforation diameter)
Flowing Bottomhole
Pressure (psig)
100
Perforation Pressure Drop
(0.7-in. perforation diameter)
0
3,000
Inflow Performance
Relationship
(0.5-in. perforation diameter)
2,000
Tubing Intake
1,000
Perforation Diameter
Perforation Length
Shot Density
Gun Phasing
Variable
7.0 in.
8 spf
45°
0
0
2,000
4,000
Liquid Rate (BLPD)
6,000
Figure 11.25 — Halliburton’s Nodal Analysis Module
performs an in-depth analysis of reservoir, fluid, wellbore,
and completion properties to predict flow rates and
pressure drops. Comparison of data from different
completion configurations allows a completion design to
be selected that will minimize or eliminate sanding and
will permit proper management of reservoir pressures for
optimal production. Assumptions and results used in
generating the graph in this figure are shown in Figures
11.27, 11.28, and 11.29.
0
2,000
4,000
Liquid Rate (BLPD)
6,000
Figure 11.26 — Besides examining the relation between flow
rate and pressure drop, the Nodal Analysis Module predicts flowing
bottomhole pressure as a function of flow rate. For the tubing
characteristics assumed in the completion design, the intersection
of the Tubing Intake curve and an Inflow Performance
Relationship curve gives the predicted flowing bottomhole
pressure and flow rate that will result for the given completion
design. Assumptions and results used in generating the graph in
this figure are shown in Figures 11.27, 11.28, and 11.29.
NOMENCLATURE
CFE = core flow efficiency
Sg = gravel-pack skin
Df = turbulent flow coefficient for formation
Sor = residual oil saturation
Dg = turbulent flow coefficient for gravel pack
Sp = perforation skin
Dp = turbulent flow coefficient for perforation
St p = two-phase (gas/oil) skin
kc = permeability in perforation crushed zone
kd = permeability in wellbore-damaged zone
ku = permeability in undisturbed formation
PR = productivity ratio
Q = liquid flow rate
S = total skin
Sc = partial completion skin
Swirr = irreducible water saturation
WFE = well flow efficiency
REFERENCES
1. An Introduction to Perforating, Halliburton, Houston, 1986.
2. Locke, S.: “An Advanced Method for Predicting the Productivity
Ratio of a Perforated Well,” 1980 SPE Annual Symposium on
Formation Damage Control, Bakersfield, California, January 28-29.
3. Bell, W.T.: “Perforating Underbalanced—Evolving Techniques,”
JPT (October 1984) 1653-1662.
Sd = damaged-zone skin
121
FRACPAC COMPLETION SERVICES
WELL EVALUATION MODEL INPUT SUMMARY
Fluid Properties
Mole Percent CO2 (%) ......................................0.00
Bubble Point @ 160˚F (psig) ..............................1,785.8
Oil Volume Factor Correction............................Vazquez/Beggs
Solution Gas Correction....................................Vazquez/Beggs
Oil Viscosity Correction.....................................Ng/Egbogah
Oil/Water Viscosity Correction ..........................Avg
Gas-Water Solubility .........................................No
Oil Gravity (˚API) ...............................................35.00
Gas Gravity (air = 1.0).......................................0.800
Water Gravity (water = 1.0) ..............................1.060
Produced GOR (scf/bbl).....................................400.0
Percent Water (%)............................................0.0
Mole Percent N2 (%).........................................0.00
Mole Percent H2S (%).......................................0.00
Wellbore Data
Flowing Wellhead Pressure (psig) ......................250.0
Flowing Wellhead Temperature .......................Heat Tran
Casing/Tubing Description
Measured Depth (ft) ......................................6,000.00
Vertical Depth (ft) ..........................................6,000.00
Vertical Deviation (˚) .......................................0.0
Casing OD (in.) ..............................................7.000
Casing ID (in.) ................................................6.366
Tubing OD (in.) ..............................................2.875
Tubing ID (in.) ................................................2.441
Flow Path ......................................................Tubing
Flow Correlation ............................................Hagedorn/Brown
Absolute Roughness (in.) ...............................0.00180
Perforating Depth, Measured (ft) ...................6,000.0
Perforating Depth, TVD (ft) ............................6,000.0
Heat Transfer Model
Heat Transfer Coefficient (BTU/hr/ft2/˚F) ............2.292
Slip Factor ........................................................1.00
Measured Depth (ft) .........................................6,000.00
Static Temperature (˚F)......................................160.0
Reservoir Description
Flow Model.....................................................Radial
Formation Permeability (md)............................1,000.000
Net Stratigraphic Pay (ft) .................................10.0
Measured Net Pay (ft)......................................10.0
Reservoir Pressure (psig) ..................................4,000.0
External Drainage Radius (ft) ...........................1,200.0
Drill Bit (in.) .....................................................10.625
Reservoir Laminar Skin ....................................Theory
Horizontal/Vertical Permeability Ratio ..............5.0
Damaged-Zone Permeability Ratio, kd /ku .........0.4
Damaged-Zone Thickness (in.).........................2.00
Reservoir Turbulence, D (d/bbl)........................Theory
Reservoir Turbulence, Beta (1/ft)......................0.5812406E+07
Oil/Gas Flow....................................................Vogel
Oil/Water Flow ................................................Segregated
Rock Type .......................................................Sandstone
Relative Permeability to Oil @ Swirr ...................0.80
Relative Permeability to Water @ Sor ................0.2
Completion Data (Perf + Pack)
Measured Peforated Interval (ft)........................10.0
Formation Top to Perforation Top (ft) ...............0.0
Gun Phasing (˚) .................................................45
Perforation Density (spf) ...................................8.00
Perforation Diameter (in.) .................................0.700
Perforation Length (in.).....................................7.0
Crushed-Zone Thickness (in.) ............................0.50
Crushed-Zone Permeability Ratio, kc /ku ............0.30
Crushed-Zone Turbulence Option .....................Dmg*Crush
Crushed-Zone Turbulence, Beta (1/ft) ...............0.3093279E+08
Casing/Cement Thickness (in.) ..........................2.13
Tunnel Calculation Method ..............................Casing ID
Tunnel Length (in.) ...........................................2.629
Gravel Permeability (md)...................................40,000
Turbulence Coefficient Method ........................Saucier
Turbulence Coefficient (1/ft) .............................0.1006400E+06
Figure 11.27 — The Nodal Analysis Module uses extensive fluid, wellbore, reservoir, and completion information
in making its flow and pressure estimates. The data shown here were used in calculations to generate the graphs
in Figures 11.25 and 11.26.
122
WELL EVALUATION MODEL
IPR / TUBING-INTAKE REPORT
IPR CURVE 1
Perforator Parameters
Perforation Diameter (in.) .................................0.7
Perforation Length (in.).....................................7.0
Shot Density (spf) .............................................8.0
Gun Phasing (˚) .................................................45.0
IPR Pressure Drop Summary
Liquid Rate
(BLPD)
Formation
Pressure Drop
(psi)
Perforation
Pressure Effect
(psi)
Gravel Pack
Pressure Drop
(psi)
____________________
Flowing
Bottomhole Pressure
at Producing Depth
(psig)
____________________
____________________
____________________
____________________
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
3,668.09
3,526.79
3,370.16
3,198.18
3,010.81
2,808.03
2,589.74
2,355.84
2,106.16
1,840.49
209.4
279.5
349.8
420.3
490.9
561.7
632.7
703.8
775.1
846.5
11.2
15.3
19.7
24.4
29.2
34.3
39.7
45.2
51.0
57.0
111.3
178.3
260.3
357.1
469.0
595.9
737.9
895.2
1,067.8
1,256.0
Absolute Openhole Flow Potential (BLPD) ..........9,056.289
Completion Skin Analysis
Flow Rate
Near-Wellbore Skin
Perforation Skin
Gravel Skin
Total Skin
Q
Sc
Sd
Stp
Df*Q
Sp
Df*Q
Sg
Db*Q
1,500.0
0.0
0.48
0.00
0.03
0.370
0.038
1.610
2.622
515
2,000.0
0.0
0.48
0.00
0.04
0.370
0.051
1.610
3.549
6.10
2,500.0
0.0
0.48
0.00
0.04
0.370
0.063
1.610
4.509
7.08
3,000.0
0.0
0.48
0.00
0.05
0.370
0.076
1.610
5.503
8.09
3,500.0
0.0
0.48
0.00
0.06
0.370
0.088
1.610
6.535
9.15
4,000.0
0.0
0.48
0.00
0.07
0.370
0.101
1.610
7.609
10.24
4,500.0
0.0
0.48
0.00
0.08
0.370
0.114
1.610
8.728
11.38
5,000.0
0.0
0.48
0.00
0.09
0.370
0.126
1.610
9.892
12.57
5,500.0
0.0
0.48
0.00
0.10
0.370
0.139
1.610
11.105
13.80
6,000.0
0.0
0.48
0.00
0.11
0.370
0.152
1.610
12.367
15.09
Q......................Flow Rate (BLPD)
Sc .....................Skin, Partial Completion
Sp .....................Skin, Perforation
Sg .....................Skin, Gravel Pack
Stp ....................Skin, Two-Phase Gas/Oil
Sd .....................Skin, Damaged Zone
S.......................Skin, Total
S
Df*Q.................Turbulence, Formation
Dp*Q ................Turbulence, Perforation
Dg*Q ................Turbulence, Gravel Pack
Figure 11.28 — The data in the previous figure and the perforator parameters shown here were used to generate
an IPR pressure drop summary and an associated completion skin analysis. IPR results are plotted in Figures 11.25
and 11.26.
123
FRACPAC COMPLETION SERVICES
WELL EVALUATION MODEL
IPR / TUBING-INTAKE REPORT
IPR CURVE 2 AND TUBING-INTAKE CURVE
Perforator Parameters
Perforation Diameter (in.) .................................0.5
Perforation Length (in.).....................................7.0
Shot Density (spf) .............................................8.0
Gun Phasing (˚) .................................................45.0
IPR Pressure Drop Summary
Liquid Rate
(BLPD)
Formation
Pressure Drop
(psi)
Perforation
Pressure Effect
(psi)
Gravel Pack
Pressure Drop
(psi)
____________________
Flowing
Bottomhole Pressure
at Producing Depth
(psig)
____________________
____________________
____________________
____________________
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
3,424.66
3,116.38
2,749.78
2,324.47
1,839.65
1,293.79
683.89
64.63
209.4
279.5
349.8
420.3
490.9
561.7
632.7
703.8
19.3
26.3
33.8
41.7
49.9
58.5
67.5
76.8
346.7
577.7
866.5
1,213.5
1,619.5
2,086.0
2,616.0
3,154.8
Absolute Openhole Flow Potential (BLPD) ..........5,065.555
Completion Skin Analysis
Flow Rate
Near-Wellbore Skin
Perforation Skin
Gravel Skin
Total Skin
Q
Sc
Sd
Stp
Df*Q
Sp
Df*Q
Sg
Db*Q
S
1,500.0
0.0
0.48
0.00
0.03
0.642
0.060
3.155
10.253
14.62
2,000.0
0.0
0.48
0.00
0.04
0.642
0.080
3.155
14.038
18.43
2,500.0
0.0
0.48
0.00
0.04
0.642
0.100
3.155
18.084
22.51
3,000.0
0.0
0.48
0.00
0.05
0.642
0.120
3.155
22.432
26.88
3,500.0
0.0
0.48
0.00
0.06
0.642
0.140
3.155
27.117
31.60
4,000.0
0.0
0.48
0.00
0.07
0.642
0.160
3.155
32.158
36.67
4,500.0
0.0
0.48
0.00
0.08
0.642
0.180
3.155
37.536
42.07
5,000.0
0.0
0.48
0.00
0.09
0.642
0.201
3.155
39.968
44.54
Q......................Flow Rate (BLPD)
Sc .....................Skin, Partial Completion
Sp .....................Skin, Perforation
Sg .....................Skin, Gravel Pack
Stp ....................Skin, Two-Phase Gas/Oil
Sd .....................Skin, Damaged Zone
S.......................Skin, Total
Df*Q.................Turbulence, Formation
Dp*Q ................Turbulence, Perforation
Dg*Q ................Turbulence, Gravel Pack
Producing Rates
IPR Curve
Tubing Intake Curve
Producing Rate (BLPD) at Intersection with IPR Curve
1
2
4,972.3
3,377.7
Figure 11.29 — The data in Figure 11.21 and the perforator parameters shown here were used to generate an
IPR pressure drop summary, a completion skin analysis, and Tubing Intake curve information. IPR results are
plotted in Figures 11.25 and 11.26, and Tubing Intake results in Figure 11.26.
124
Chapter 12
INTRODUCTION
This chapter focuses on the various
methods used to complete high-permeability formations. Completion methods
depend on formation type; therefore, the
discussion of completions is divided into
formations with high, moderate, and no
sanding tendency. These formations can
be treated with gravel-pack or FracPac,
OptiPac, and OptiFrac applications.
concerns of performing a gravel-pack
treatment, FracPac treatment, or
both, including wellbore conditions,
workstring considerations, sand and
screen selection, service tools, gravelpack packers, and sump packers. The
many applications that are possible for
high-sanding-tendency formations are
also discussed.
COMPLETIONS FOR HIGHSANDING-TENDENCY
FORMATIONS (FRACPAC)
Wellbore Conditions
Gravel-pack techniques and systems have
come a long way from the days of simply
running a slotted liner into the well
and dumping sand down the annulus.
Pumping systems, circulating valves,
packers, screens, and other gravel-pack
placement tools have evolved into
systems that perform all of the gravelpack and fracturing procedures in a
single trip of the workstring. In addition
to quick deployment, the downhole
equipment used must withstand the
increased forces exerted during high-rate
gravel-packing and fracturing treatments.
Halliburton has developed some of the
most cost-effective, reliable completion
equipment in the industry and has
recently developed the HIGH-RATE
downhole tool system for gravel-pack
and FracPac completions in 5-inch and
5-1/2-inch casing sizes.
Efficient fluids have been developed for
effective delivery of proppant into the
fractures, perforations, and annuluspack area. These fluids are designed to
enhance cleanup after fracturing and
packing operations are completed. The
following sections focus on the many
Well
Completions
When designing a gravel-pack or FracPac
completion, several considerations are
critical to the safety of the well and to the
efficiency of the completion. Casing size,
weight, and grade should be identified,
along with the workstring and tubing
size, weight, grade, and thread type. The
depth that the downhole components
will be set, the presence of H2S or CO2
in the produced effluents, bottomhole
temperature, bottomhole pressure,
completion fluid, and well deviation
will determine the type of downhole
components that can be used. Perforation
depth, density, and phasing, along with
remedial cement-squeezed areas in the
well should also be known.
The forces encountered during the
gravel-pack and FracPac job place
substantial forces on the workstring.
Fluid pressure and temperature changes
inside and outside of the workstring
during circulating and injection can
cause piston, friction, balloon, thermal,
and buckling effects to occur. These
effects can be pronounced and should
be anticipated when selecting the
downhole tool systems and techniques
to be used. Halliburton and other
companies have developed numerous
125
FRACPAC COMPLETION SERVICES
All-Welded, Wire-Wrapped Screen
pieces of software specifically designed to calculate the
forces exerted on the workstring during gravel-pack and
FracPac pumping applications.
Workstring Considerations
Figure 12.1 — All-welded, wire-wrapped screens are an industry
standard. The wire that wraps the vertical ribs is keystone shaped
to avoid plugging with sand. Well conditions determine exact
metallurgy required, but the standard screen is stainless-steel
screen on carbon-steel base pipe.
Perforated Prepack Screen
Figure 12.2 — Perforated prepack screens have an inner screen
and an outer perforated case. Epoxy-coated, thermally set gravel
is placed in the annulus between the inner screen and outer
case. The primary application for this type of screen is in open
hole with no sand pumped as an annular pack.
126
The workstring used for FracPac and gravel-pack completions should be selected based on hole depth and angle,
packer bore size, set-down weight requirements, overpull
requirements, and workstring OD to casing ID. The
workstring should be cleaned internally and externally
before it is run into the well. All threaded connections
should be inspected, and pipe dope should be applied to
the pin (male) joints. The workstring should be degreased
with a caustic solution and pickled with acid before gravel
packing to remove any pipe dope, oil, mill scale, and rust
from the internal surfaces. Workstring sizes larger than
3-1/2 inches can create slurry pumping problems.
Sand and Screen Selection
The primary goal of gravel packing is to prevent the
production of formation sands without limiting the flow
of hydrocarbon to the wellbore. Proper sizing of the gravel
and its inherent pore space is the most important decision
made concerning the gravel pack. Formation samples are
put through a sieve analysis to determine particle size.
With the formation particle size identified, a proper size
of pack gravel can then be chosen.
Through tests that were performed to identify the optimum
grain size for gravel packs, it was determined that average
grain size of the pack gravel should be 5 to 6 times the
formation sand size at the 50 percentile (median) point of
the sieve analysis.1 This ratio of 5 to 6 times the formation
sand size appears to provide absolute stoppage of formation
sand flow into or through the gravel-pack medium. A more
detailed discussion of sand is presented in the proppant
and proppant selection chapter (Chapter 10). For FracPac
applications, where conductivity within the fracture is
important, larger sand sizes have been used successfully.
Screened portions of the tubing string provide an entrance
for incoming oil production while at the same time
retaining the gravel pack. The wire spacing on the screen
should be narrower than the smallest sand selected for the
gravel pack. For optimum performance in a cased hole, the
screen OD should have 1 inch of radial clearance from
the casing ID. In an open hole, the screen OD should
have 2 inches of radial clearance from the borehole wall.
Maintaining these clearance criteria helps eliminate gravel
bridging in the annulus and makes a washover easier if a
remedial workover becomes necessary. Refer to Figure 12.1
through Figure 12.4 for the various types of screens used
in gravel-pack and FracPac completion services. In most
applications, the wire-wrapped screen shown in Figure 12.1
is used, but in some angled wells and in wells where
customer preference or special requirements arise, prepacked
screens such as those shown in Figures 12.2 through 12.4
are placed.
Centralized blank pipe is normally used to extend from the
top joint of screen to the bottom of the gravel-pack tool
assembly. Each joint of blank pipe should be centralized
the same way as the screened sections. The collars used
with blank pipe should be lathe-turned and beveled to
help eliminate flow turbulence, ease running into a liner
top, and ease washover during a remedial workover. The
grade of blank pipe selected must withstand maximum
collapse forces exerted during gravel-pack sandout and
FracPac operations. The use of high-yield grades of blank
pipe is mandatory on FracPac completions.
Gravel-pack screens should be centralized every 15 ft.
Welded blade-type centralizers are commonly used in
cased hole applications; however, centralizers are now
available that are welded to small spacers in the screen
jacket. These smaller spacers provide more flow area across
the screen surface by not requiring blank pipe for welded
attachment. Screens that are used in openhole gravel-pack
completions should have bow-spring centralizers installed
at 15-ft intervals.
Special Clearance Prepack Screen
Figure 12.3 — Special clearance prepack screens are used when
the ID and OD requirements of a standard, non-prepacked
screen are needed. These screens have an inner microscreen and
a standard outer screen, with gravel in the space between them.
The gravel can be uncoated or epoxy coated and is much thinner
than other prepack screens.
Dual-Screen Prepack
Cased-hole screened intervals should include up to 5 ft of
overlap below the perforated zone and a minimum of 5 ft
above the perforated zone. This additional screened area
allows for inaccuracies in depth measurement and provides
additional gravel reserves above the producing zone to
compensate for any natural settlement of the gravel pack.
Before any screen is run into the well, it should be checked
to ensure that it is the correct gauge by inserting a feeler
gauge into the openings of the screen. Verify that the base
pipe inside the screen has been drilled by flushing water
through each joint of screen. This water flush also helps
wash out any debris left from manufacturing processes and
debris that may have collected during shipment. Visually
inspect each joint of screen to make sure it was not damaged
during shipment. Check each joint of screen and blank to
verify that each is still within drift (straightness) tolerances.
Figure 12.4 — The dual-screen prepack has two screens. A
gravel layer is placed between a standard inner screen and a
standard outer screen. The prepack provides gravel-pack type
filtering when gravel packing is not feasible, or when special
sand control is required.
127
FRACPAC COMPLETION SERVICES
DOWNHOLE TOOL SYSTEMS
Accessories for the Multiposition Tool
Downhole tool systems for gravel-pack and FracPac
Completion Services are versatile in configuration and
perform multiple functions. Halliburton’s standard multiposition tool system can be combined with numerous
specialty subs, screens, blanks, liners, and packers to perform
any of the FracPac Completion Services required. This
system is especially attractive to operators because of the
rig time savings provided by running and setting the screen
assembly and performing the fracturing and gravelpacking portions of the FracPac procedure in a single trip
of the workstring.
Accessories for the multiposition tool are available to
allow positive indication of all service tool positions. For
FracPac applications, normally the circulating and reverse
positions are indicated.
Multiposition Service Tool
The multiposition service tool is at first used to set the completion packer, and then directs fluid flow for the toolstring.
Depending upon the type of job being performed, the
multiposition tool can have either three or four positions.
These positions are squeeze, circulating, upper circulating,
and reverse. Each of these positions is discussed later in this
chapter, based on the type of application being performed.
The multiposition tool service tool has two exit ports,
phased 180° apart for the 5-inch and 5-1/2-inch tool sizes.
For larger tool sizes, the multiposition tool has three ports
phased 120° apart. These multiple-exit-port designs allow
for large flow area, which diffuses fluid flow to prevent tool
erosion. Table 12.1A in the appendix at the end of this
chapter lists the flow rates for all available multiposition
tool sizes.
Two alternate service tool configurations are available. The
first is a “weight-down” version that eliminates the need
to manipulate the workstring to establish the squeeze or
circulating positions. By applying weight down on the
packer, workstring contraction caused by thermal forces,
balloon forces, and tool movement during pumping is
negated. Additional set-down weight can be added as
required during the job. The weight-down multiposition
tool requires that the casing above the packer be able to
withstand the high pressure exerted during the gravel-pack
sandout or FracPac job.
The second service tool configuration is the HIGH-RATE
service tool. The HIGH-RATE service tool also uses the
weight-down feature mentioned earlier. Throughput flow
area has been increased to maximize pumping-rate
capability and reduce erosion of the tool. This tool is
available for use in 5-inch and 5-1/2-inch casing sizes.
128
Gravel-Pack Packers
The VERSA-TRIEVE® retrievable packer or the
PERMA-SERIES permanent packer can be deployed with
the multiposition tool and can function as the gravel-pack
packer, fracturing packer, and production packer. Packer
sizes range from 4-1/2 inches to 10-3/4 inches. Both packers
are available with various top sub configurations. Refer to
Table 12.2A and Table 12.3A in the appendix at the end
of this chapter for the complete ranges and specifications
of available VERSA-TRIEVE and PERMA-SERIES packers.
Sump Packers
In addition to the tool-system components already
discussed, sump packers are typically used in combination
with multiposition tools. The sump packer is usually set
with electric wireline and is normally considered a permanent installation. The packer is set below the perforations
and is used for depth correlation of the production screen
to the perforated interval.
A sump-packer seal assembly is attached to the bottom of
the production screen, and the screens are then configured
as needed for the well conditions. The workstring is run
into the hole until the sump-packer seal assembly engages
into a receiving bore in the sump packer. A collet guide is
used to provide a positive snap engagement that is felt at
the surface and verifies that the seal assembly is fully
engaged with the sump packer.
The sump that is created below the sump packer provides
a trap for debris that settles after perforating and for lost
tools to fall through. Also, the sump allows logging tools to
be lowered past the perforations so that the entire interval
can be surveyed for future operations. Refer to Table 12.3A
in the appendix at the end of this chapter for the full
range of available sump packers for use with the
multiposition tool system.
Applications
The multiposition service tool system can be configured
with numerous combinations of subs, screens, blanks,
and packers to form any of the following systems:
• Single-zone FracPac System and gravel-pack system
• Stacked (multiple-zone)FracPac and gravel-pack system
• Washdown system
succession up the hole. As many as five zones have been
packed and produced individually within a single
wellbore.
When one zone is depleted, a bridge plug is set to isolate
the depleted zone. The bridge plug is usually set in a
landing nipple that was run as part of the concentric
production string. Once the plug is set, either a sliding
side door device may be shifted or the concentric string
can be perforated to establish flow communication with
the formation.
• One-trip perforation and pack system
• Absolute isolation system
Dual-Zone Completion
• Horizontal system
Another multi-zone completion is when dual zones are
completed and produced separately. See Figure 12.7 for
a schematic of a dual-zone completion. A sealbore is
placed as part of the lower-zone production seal assembly.
This sealbore and its accompanying seal unit isolates the
lower production zone during FracPac and gravel-pack
procedures. Production from the lower zone flows up the
long-string production tubing while flow from the upper
zone flows between the OD of the long string and the ID
of the upper gravel-pack packer. Upper zone flow then
continues up the short-string production tubing.
• Single-trip, multi-zone system
• High-rate, high-pressure FracPac system
• Slimhole system
• Floater system
Single-Zone FracPac and
Gravel-Pack System
The multiposition service tool has four positions. Three
positions are used to pump a FracPac job, and a fourth
position is commonly used to pump long, high-density
gravel-pack intervals. The positions used in a FracPac
application are squeeze, circulate, and reverse. Positions
used for a gravel-pack application are squeeze, lower
circulate, upper circulate, and reverse. Refer to Figure
12.5 for a schematic and discussion of the pumping
stages of a single-zone FracPac application.
Multi-Zone FracPac and
Gravel-Pack Systems
Selective Zone Completion
Many variations of multi-zone FracPac and gravel-pack
applications are possible. The most common applications
are selective-zone completions and dual-zone
completions. A selective FracPac and gravel pack may be
applied when two or more zones have been completed
and one of the zones is produced through a single string
of tubing. Refer to Figure 12.6 for a schematic of a
selective-zone completion. Normally the lower zone is
produced first, and the remaining zones are produced in
Washdown System
The multiposition tool is available in the washdown
version( Figure 12.8). When the washdown multiposition
tool is used, a washdown shoe is added to the bottom of the
screen assembly. This tool configuration allows formation
fines and debris to be removed from the wellbore before
placing the gravel-pack or FracPac treatment.
One-Trip Perforate and Pack System
(FracPac Optional)
The one-trip perforate and pack system provides the
versatility and time savings of running a perforating
assembly with a retrievable gravel-pack packer/production
packer in a single trip. Refer to Figure 12.9 for a schematic
of the one-trip perforate and pack system. This system
should be used to perforate intervals up to 50 ft long with
well deviation angles less than 45°. At deviation angles
over 45°, spent perforating equipment and debris may
not fall completely to the bottom of the well, making
operations difficult.
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FRACPAC COMPLETION SERVICES
FracPac
Circulate
FracPac
Squeeze Position
Gravel Pack Packer
Screen
Sump Packer
FracPac
Reverse
Gravel Pack
Packer
Screen
Sump
Packer
Figure 12.5 — The FracPac workstring in squeeze position varies little from the multiposition service tool
configuration used to pump gravel packs. The standard multiposition service tool and flow subs have been
upgraded to allow for high-pressure, high flow rate slurries. The slurry is squeezed into perforations and fractures,
until the proppant fills in to the wellbore, when screenout occurs.
The FracPac workstring in circulate position allows returns to be taken back to the surface. For FracPac service, the
blank liner must be able to withstand exerted FracPac squeeze pressures. In circulating position, the flowback rate
can be controlled to achieve a tight annular pack.
The FracPac workstring in reverse position allows pump pressure to be applied down the annulus, and returns to
be taken up to the surface in the workstring. On a standard FracPac string, the workstring is raised approximately
9 ft to actuate the reverse position. The formation is isolated (not totally) from the pump pressure by the reverse
ball-check shown in red.
130
FracPac
Selective-Zone Completion
FracPac
Dual-Zone Completion
Dual Hydraulic-Set Packer
Gravel-Pack Packer
Gravel-Pack Packer
Upper Screen
Upper Screen
Lower Screen
Lower Screen
Sump Packer
Sump Packer
Figure 12.6 — The FracPac workstring can be configured
for selective-zone completion. The lower zone is normally
produced first with successive zones up the hole
produced subsequently. This allows lower, depleted zones
to be plugged back. As many as five zones in a single
wellbore have been individually packed and produced.
Figure 12.7 — The FracPac workstring can be configured
for a dual-zone completion. The lower zone is produced
up the long-string production tubing, and the upper zone
is produced between the OD of the long string and the ID
of the gravel-pack packer.
131
FRACPAC COMPLETION SERVICES
Wash Down/
Fluid Conditioning
Circulating/
Packing Position
Circulating (Preperforating) Position
From the bottom up, the components of the one-trip
perforate and pack system are the perforating guns,
automatic-release drop-bar firing head or pressureactivated firing head, reciprocation-set packer (without an
integrated equalizing bypass), bypass valve, lower O-ring
sub or seal sub, tell-tale screen, O-ring sub, production
screen, blank, ceramic flapper valve, and the retrievable
gravel-pack assembly. A radioactive marker (RA tag) is
normally run one joint above the multiposition service tool.
This marker provides a stimulus for the gamma-ray depth
correlation tool that is later run on wireline.
Perforating Position
The downhole assembly previously discussed is run to the
desired depth. Wireline is then run through tubing to
provide positive depth correlation. The assembly, with the
aid of the wireline correlation, is spaced across the zone of
interest and the reciprocation-actuated GO packer is set.
The bypass valve above the GO packer is opened and
diesel or nitrogen is pumped to displace the packed-off
area and provide the desired pressure for underbalanced
perforating. The bypass valve is then closed to isolate the
annulus above the GO packer.
When the downhole environment is ready, a drop bar is
dropped down the tubing to fire the perforating guns. Upon
firing, the guns are released and fall to the bottom of the
hole. A predetermined amount of formation fluids are
produced to clean the perforation tunnels. The bypass
valve is then reopened and the hydrocarbons are flowed out
of the tubing.
Before retracting the GO packer the bypass valve is shut and
pressure is applied to the annulus. This annular pressure
opens the annular bypass valve while rig pull is applied to
release the GO packer. The annular-pressure-operated
bypass valve prevents a possible fluid lock from occuring
in the system. After the GO packer releases, the entire
assembly is lowered until the screen is properly positioned
across the perforated interval. Then, the GO packer is
reset and the gravel-pack packer is set. The downhole tool
assembly is now ready for the gravel-pack portion of the
perforate and pack application.
Squeeze Position
Figure 12.8 — The washdown system has a washdown shoe
added to the bottom of the toolstring, allowing the wellbore to
be washed free of fines and debris before a gravel-pack or
FracPac treatment is performed.
132
The squeeze position of the multiposition service tool
allows the gravel-pack media to be pumped downhole into
fractures, perforations, and the annular pack area. Tool
functions are actuated by a setting dart that is dropped
Circulating
Position/Perforating
Perforating
Squeeze
Position
Lower
Circulating
Position
Pack Completed
Formation Isolated
Tubing
Multiposition
Tool
Gravel-Pack
Packer
Flapper
Valve
(Open)
Flapper
Valve
(Closed)
Production
Screen
O-Ring Sub
Telltale
Screen
GO Packer
Gun-Release
Sub
Perforating
Guns
Figure 12.9 — The Perforate and Pack configuration can be run for FracPac applications or gravel packs.
Since perforating and packing are accomplished in a single trip, rig-time savings can be substantial.
133
FRACPAC COMPLETION SERVICES
Absolute Isolation
System (AIS)
down the tubing string at the beginning of the squeeze
stage. The setting dart first allows the packer to be set and
tested against the pressure applied to the annulus. Then,
by using rig pull and pressuring the tubing, the dart is
forced farther down the tool where it will seat and block
the gravel-pack ports. Pressuring the tubing string again
opens the gravel-pack ports and rig weight is applied to
lower the service tool into squeeze position. The setting
dart now functions as a plug for gravel packing and as a
ball check valve to prevent fluid loss when the tool is in
the circulating and lower circulating positions.
Multiposition
Tool
Gravel-Pack
Packer
Lower Circulating Position
Rig pull is applied to the downhole assembly to move the
multiposition tool from the squeeze position to the
circulating position. Returns are collected at the screen
and flow up the washpipe.
Pack Completed
When the gravel-pack portion of the perforate and pack
application is completed, the service tool is retrieved from
the well. As the washpipe is pulled uphole it releases a
prop from the flapper, allowing the flapper to seat. The
formation is now isolated from the wellbore fluids.
Absolute Isolation System
Production
Screen
Washpipe
Telltale
Screen
The Absolute Isolation System (AIS) is a downhole tool
system that allows the FracPac or gravel-packed interval
to be isolated from the annulus fluids before retrieving
the multiposition service tool from the wellbore. Refer to
Figure 12.10 for a schematic of the Absolute Isolation
System. During the packing procedure, the washpipe
functions as a return string. After the packing portion of
the service, the washpipe forms an inner isolation string to
protect against fluid loss to a lower-pressured formation
and fluid flow from a higher-pressured formation. If fluid
control is not a problem, the washpipe can be removed
with the service string after the gravel pack is placed.
Sump
Packer
Horizontal Systems
Figure 12.10 — The Absolute Isolation System allows FracPac- or
gravel-pack-treated intervals to be isolated from annular wellbore
fluids before retrieving the multiposition service tool from the
hole. The washpipe functions as an inner isolation string after the
packing portion of the service has been performed.
134
FracPac Completion Services offers fracturing and sand
control for horizontal well applications in both the cased
and openhole sections of the well. Refer to Figure 12.11
for a schematic of horizontal systems. Such horizontal
applications present unique problems in deploying,
setting, and retrieving sand-control equipment. Also,
formation irregularities and the way they intersect the
horizontal borehole present challenges to sand-control
Cased Hole
Completion
Lower Circulate
Position
Cased Hole
Completion
Squeeze Position
Cased Hole
Completion
Upper Circulate
Position
Openhole
Completion with
Inflatable Isolation
Packers
Workstring
Production
Seal Unit
Upper Ports
Gravel-Pack
Packer
Lower Ports
Ported Flow
Sub
(Closing
Sleeve
Optional)
Horizontal
Ball Seat
Positive
Indicator
(Optional)
Shear Joint
Inflatable
Packer
Wash Pipe
Production
Screen
Inflatable
Packer
Telltale
Screen
Sump Packer
Float Shoe
Positive
Indicator
(Optional)
Figure 12.11 (shown vertical for clarity)— The FracPac string can be run into highly deviated and
horizontal wells. Getting to depth, setting the tool, and retrieving the tool generally present
problems in horizontal applications. Both cased and uncased intervals can be treated. Inflatable
straddle packers isolate openhole intervals.
135
FRACPAC COMPLETION SERVICES
measures. Vertical fractures can lead to water coning
and heterogeneous intervals can exert different pressures
and producing capabilities, requiring special isolative
completion techniques.
Uncased sections of the wellbore can be isolated by running
inflatable openhole packers. The packers are inflated with
either wellbore fluid or cement. The use of the flapper
shoe at the bottom of the string provides a circulating
and reverse-circulating flow path for fluid within the
workstring. This circulating fluid removes cuttings from
the low side of the horizontal wellbore and helps push
through openhole bridges.
Other positions of the multiposition service tool actuate
the circulating, reverse positions and set the retrievable
and inflatable packers.
Single-Trip, Multi-Zone Gravel-Pack
Systems (FracPac Optional)
Multiple zones can be packed off and gravel packed with
the single-trip, multi-zone system. A standard sump packer
and retrievable gravel-pack packer are run as the bottom
and top packers, respectively. To isolate the multiple zones
between the sump and gravel-pack packer, inflatable
isolation packers are deployed.
The downhole equipment is positioned with the help of a
sump packer that has already been set with wireline.The
sump packer provides a positive connection with the collet
on the lower end of the workstring that is being lowered.
The collet engages with a positive snap to indicate the
string has bottomed in the sump packer.
The retrievable gravel-pack packer at the top of the string is
the first component set after the desired depth is reached.
Hydraulic force provided by the hydraulic setting tool
extends the packer elements and slips to the casing wall.
The lower isolation packer is now inflated by applying
2,000 psi of pump pressure down the workstring. After
the packer is fully inflated, it is tested for pressure integrity.
Fluid is injected into the formation. If the packer showed
a leak, the leak would occur up the annulus. Returns at
the surface would be seen only if all of the zones uphole
from the lower packer were not taking fluid. Each
successive isolation packer is tested against the open lower
zones, unless all of the isolation packers are spaced at
equal distances along the string. After all isolation packers
are set and tested, pressure is applied down the annulus to
actuate the setting dart. The setting dart opens the return
flow path. The downhole zones are now ready to receive
gravel-pack media.
136
The bottom zone is gravel packed first, followed by each of
the zones as they progress uphole. Unless all of the gravelpack assemblies are spaced equally, the lower zone or zones
will remain open while the zone of interest is being packed.
Slimhole System
A number of products and tool components are now
available to perform gravel packing through tubing.
Although jointed tubulars are still used, the downhole tool
system for slimhole applications is now commonly deployed
on coiled tubing. The downhole tool system can be set
on bottom, located in landing nipples, or located in the
tubing string. These systems are generally applicable for
short perforated intervals. The treatment is pumped, as
mentioned previously, through either an existing tubing
string, or a jointed or coiled tubing string that is run
concentrically. Tool systems are available for 2-3/8-inch
through 4-inch tubing sizes. Refer to Figure 12.12 for a
schematic of available slimhole configurations.
Floater Gravel-Pack System
Floater gravel-pack systems are designed to compensate for
vessel heave in offshore gravel-pack applications. Floater
system tool positions are actuated with rig weight down.
The lower circulating, upper circulating, and reverse
postions of the service tool and components allow for 6 ft
of vessel heave upward and 6 ft downward. The tool
systems may vary from single-zone FracPac or gravel-pack
applications by lengthening the packer assembly for vessel
heave and adding compression indicators for locating tool
positions. Two types of position indicators are available
for use with floater systems. One provides consistent,
snap-through indication, and the other uses compressive
loading for position indication.
Figure 12.13 shows a floater gravel-pack system. The
gravel-pack assembly was extended a total of 24 ft to
compensate for vessel heave.
COMPLETIONS FOR MODERATESANDING-TENDENCY FORMATIONS
(OPTIPAC)
Formations with high permeability and moderate sanding
tendency can be kept from sanding by alternative methods
to gravel pack with its screen and large annulus packs. The
FracPac completion service for this type of application is
OptiPac. OptiPac consists of a tip-screenout fracturing
procedure in which a final stage of resin-coated proppant
is pumped.
Fluted
Hanger
Dual Screen
Methods
Locator
Hanger
Concentric
Screen
GO Packer
Overshot
Fluted
Hanger
Locator
Assembly
Wireline
Fishing
Neck
Bow
Spring
Centralizers
Figure 12.12 — Slimhole FracPac and gravel-pack systems provide fracturing and packing capability through
some sizes of existing production tubing. Performing these services on coiled tubing is becoming more and
more popular. Tool systems are available to run concentrically in tubing sizes from 2-3/8-inches to 4-inches.
137
FRACPAC COMPLETION SERVICES
Floater System
Lower
Circulate
Upper
Circulate
Squeeze
Position
Reversing
Out
Multiposition
Service Tool
Gravel-Pack
Packer
Flow Sub
Production
Screen
O-Ring Sub
Telltale
Screen
Sump
Packer
Figure 12.13 — FracPac and gravel-pack services can be run in offshore conditions that require extreme
positioning flexibility for drilling vessel heave. These tool systems provide longer packer assemblies to protect
against workstring movement while allowing as much as 6 ft of vessel heave upward and 6 ft downward.
138
Resin-coated proppants are supplied in several different
forms: precured, partially cured, curable, and coated onthe-fly. These coated proppants are used for OptiPac
applications to form a permeable, stable proppant pack at
the wellbore that restricts proppant flowback and formation
sand flow. The proppant grains bond at their points of
contact when pressure is applied by closure stresses in the
fracture, forming a consolidated yet conductive proppant
pack without flow-restrictive hardware such as screens
and a full-annulus gravel pack. Refer to Proppant and
Proppant Selection in Chapter 10 of this publication for
a more thorough discussion of resin-coated proppants
and their application.
Workstring Components and
Considerations
OptiPac procedures are performed much the same as any
fracture stimulation. The workstring consists of a retrievable
packer run to setting depth in the wellbore on a tubing
string. The packer is set, and the fracturing fluids and
proppants are pumped through the tubing. Generally, the
annulus between the tubing and casing is pressured so
that any leakage across the packer can be detected at the
wellhead. Several variations of packers and other isolation
hardware are used to pack off perforated zones from other
production zones or the remainder of the casing volume.
Retrievable Packers
Retrievable packers are run and set on the end of the
workstring to isolate the perforated zone to be fractured
from the balance of the casing volume. Retrievable tools,
as a general rule, must be removed from the wellbore
before the well is put on production.
Integral-Bypass Packer
One type of packer that is used in OptiPac applications is
an integral bypass, full-opening packer suited for fracturing,
acidizing, testing, and squeezing. Packers usually consist
of a packer-body assembly, a circulating-valve assembly,
and sometimes a safety joint. The packer body includes a
J-slot mechanism, mechanical slips, elastomeric sealing
elements, and hydraulic slips. Drag springs or blocks on
the lower body resist rotation when rig torque is applied
to set or retract the packer.
Other features that make the integral bypass retrievable
packer attractive for OptiPac service are
• The full-opening mandrel permits large volumes of fluid
to be pumped through the packer and perforating guns
and wireline tools to easily pass through for operations
in the packed-off interval.
• Since the packer sets and retracts, it can be used for
multiple operations in a single trip into the well.
• Large, heavy-duty slips are set with hydraulic force
generated below the packer to reinforce the elastomeric
seals of the packer and prevent differential pressure
from pushing it uphole.
• Even though the packers are retrievable, they have very
high differential pressure ratings.
• The full-opening, retrievable packers cover a wider
range of pipe and casing sizes than most retrievable
packers. This wider range of sizes is useful in strings
that have mixed weights of casing and pipe installed.
• The integral bypass helps wellbore fluids pass around the
large diameter packers when the tool is being run into
the well. Also, the bypass provides a means of equalizing
the pressure on both sides of the packer and in some
operations can be used to spot fluids above the packer.
Concentric-Bypass Packer
Another alternative retrievable packer is the concentricbypass device. Such packers are designed for use in deviated
and horizontal wells since less reciprocating force and torque
is required to set and retract the packer. The concentric
bypass design of the packer ensures a fluid path around the
slips when cleanup from a squeeze job such as OptiFrac is
performed. Other features that make the concentric
bypass, retrievable packer attractive for OptiPac service are
• This type of packer can handle high-rate, high-volume
treatments that contain high sand concentrations.
• Straight, upward pull on the workstring opens the
bypass and retracts the packer easily, especially in
deviated and horizontal wells where torque and reciprocating rig force are lost due to bends in the workstring.
For full size ranges and specifications of retrievable packers
used in OptiFrac treatments refer to Table 12.4A through
Table 12.7A in the appendix at the end of this chapter.
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FRACPAC COMPLETION SERVICES
Retrievable Bridge Plugs
Retrievable bridge plugs are used to isolate lower sections
of casing from squeezing, treating, or testing operations
being performed on an interval above. The lower sections
of the well that are being protected may be perforated
intervals, openhole sections, or uncemented casing.
Halliburton recommends that a packer-type, retrievable
bridge plug be used in OptiPac applications. The packer
can be run alone on tubing or below one of the retrievable
packers previously mentioned. Bridge plugs are run into
the hole, set, and then released from the tubing or from
below the packer. They are left in place until the tubing
or retrievable packer is reattached. The bypass valve is then
opened, and the slips are released to trip the workstring
out. Sand is spotted on top of the bridge plug to prevent
other debris from settling around the retrieving neck during
operations in the packed-off zone. The bridge plug can be
moved and reset at another depth in the well or removed
from the well after the treatment is complete.
The packer-type bridge plug recommended for OptiPac
service has other advantages such as
• The packer-type sealing elements are less susceptible to
damage than cup-type elements used on other bridge
plugs. This is because the sealing elements are not in
direct contact with casing while tripping into the well.
• Once set, this bridge plug does not move up and
down in the casing, regardless of pressure reversal
across the plug.
• Packer-type bridge plugs are preferred in heavily
perforated casing since they are not in direct contact
with casing in transit and conform to irregularities in
the casing wall much easier than cup-type bridge plugs.
• Packer-type sealing elements are advantageous in heavy
well-fluid systems and in wells that require the packer
to enter a liner top on the way to setting depth.
Retrievable bridge plugs are available in a full range of
sizes and pressure ratings for use in OptiPac service.
140
COMPLETIONS FOR NO-SANDINGTENDENCY WELLS (OPTIFRAC)
Formations with high permeability and no sanding
tendency generally need stimulation techniques performed
that bypass near-wellbore damage. The FracPac completion
service prescribed for this type of well is OptiFrac. OptiFrac
is a tip-screenout fracturing procedure that creates wide,
short fractures to bypass permeability damage in the nearwellbore region. This permeability damage can be caused
by invasion of drilling fluids, invasion of completion
fluids, and instability in the perforation tunnels.
Techniques such as oriented perforating and components
such as resin-coated proppants are used in the OptiFrac
service to enhance fracture propagation and conductivity.
Refer to Proppants and Proppant Selection (Chapter 10), for
more detailed information about resin-coated proppants.
OptiFrac jobs are pumped by lowering an open-ended
packer into the well on the tubing string. No mechanical gravel-pack equipment is placed in the well. Refer to
Job Procedures and Best Practices, (Chapter 14), for
more detailed information on job sequence for
OptiFrac applications.
REFERENCES
1. Saucier, R.J.: “Gravel-Pack Design Considerations,” Paper 4030,
47th Annual SPE and AIME Fall Meeting (1972) 16.
APPENDIX
This appendix contains size ranges and specifications in tabular form for the components
discussed previously in the main body of the chapter.
Table 12.1A — Multiposition Tool Sizes and Flow Rates
MPT Tool Size
(in.)
Maximum Flow Rate
(bbl/min)
2.55 and 2.75
8
2.55 and 2.75 HIGH-RATE
15
3.25
16
3.88
23
5.00 standard
23
5.00 special
36
Table 12.2A — Versa-Trieve Packers
Casing
Size
Casing
Weight
Packer
OD
Packer
Bore ID
Production
Seal Assembly ID
(in.)
(mm)
(lb/ft)
(in.)
(mm)
(in.)
(mm)
(in.)
(mm)
4.500
114,30
9.5 - 11.6
3.82
97,30
2.380
60,45
1.735
44,07
5.000
127,00
15 - 18
4.09
103,89
2.55
64,77
1.927
48,95
23.2 - 24.1
3.82
97,03
2.380
60,45
1.735
44,07
14 - 17
4.67
118,62
22.750
69,85
1.927
48,95
20 - 23
4.50
114,30
20 - 24
5.73
145,54
5.000
6.625
139,70
168,28
17 - 23
7.000
7.625
177,80
193,68
9.625
196,85
59,69
2.350
59,69
3.880
89,55
3.050
77,47
82,55
2.350
59,69
98,55
3.050
77,47
145,54
3.250
82,55
2.350
59,69
5.82
147,83
3.880
98,55
3.050
77,47
6.68
169,67
3.250
82,55
2.350
59,69
3.880
98,55
3.050
77,47
3.250
82,55
2.350
59,69
3.880
98,55
3.050
77,47
3.250
82,55
2.350
59,69
3.880
98,55
3.050
77,47
3.250
82,55
2.350
59,69
3.880
98,55
3.050
77,47
3.880
98,55
2.350
59,69
5.000
127,00
3.850
97,79
3.880
98,55
2.350
59,69
5.000
127,00
3.850
97,79
32 - 38
5.73
32 - 35
24 - 29.7
46.1 - 48.6
2.350
82,55
3.250
6.00
29.7 - 39
156,72
82,55
3.880
23 - 29
39 - 47.1
7.750
6.17
3.250
3.250
6.44
6.17
6.17
36 - 43.5
8.52
43.5 - 53.5
8.30
152,40
163,58
156,72
156,72
216,41
244,48
210,82
141
FRACPAC COMPLETION SERVICES
Table 12.3A — Perma-Series® Production Packers
Casing
Size
(in.)
(mm)
4.500 114,30
5.000 127,00
5.500 139,70
Casing
Weight
7.000
7.625
9.625
168,28
177,80
193,68
244,48
Optional Seal
Unit ID*
(lb/ft)
(in.)
(mm)
(in.)
(mm)
(in.)
(mm)
(in.)
(mm)
(in.)
(mm)
(in.)
(mm)
3.790
96,27
2.555
64,90
1.677
42,60
1.810
45,97
1.910
48,51
1.920
48,77
9.5 - 13.5
3.720
94,49
2.375
60,33
1.530
38,86
1.735
44,07
13.5 - 15.1
3.600
91,44
2.375
60,33
1.530
38,86
1.735
44,07
13.5 - 15.1
3.640
92,46
2.555
64,90
1.677
42,60
1.810
45,97
1.910
48,51
1.920
48,77
15 - 21
3.960 100,58
2.555
64,90
1.677
42.60
1.810
45,97
1.910
48,51
1.920
48,77
1.920
48,77
**15 - 21
3.960 100,58
3.120
79,25
2.390
60,71
23.2 - 24.2
3.790
96,27
2.555
64,90
1.677
42.60
1.810
45,97
1.910
48,51
13 - 20
4.540
115,32
2.750
69,85
1.830
46,48
1.920
48,77
1.927
48,95
13 - 20
4.540
115,32
3.000
76,20
1.927
48,95
2.240
56,90
2.330
59,18
20 - 26
4.360
110,74
2.750
69,85
1.830
46,48
1.920
48,77
1.927
48,95
20 - 26
4.360
110,74
3.000
76,20
1.927
48,95
2.240
56,90
2.330
59,18
4.360
110,74
63,75
1.920
48,77
1.927
48,95
3.500
88.90
2.510
17 - 32
55,468 138,39 2.750
69,85
1.830
46,48
17 - 32
55,468 138,39
3.250
82,55
2.350
59,69
20 - 24
5.687
144,45
4.000
101,60
2.970
75,44
17 - 20
6.250
158,75 4.000
101,60 2.970
75,44
1.920
48,77
1.927
48,95
17 - 23
6.180
156,97
3.250
82,55
2.350
59,69
1.920
48,77
1.927
48,95
20 - 26
6.000
152,40
4.000
101,60
2.970
75,44
23 - 38
5.687
144,45 2.750
69,85
1.830
46,48
23 - 38
5.687 144,45
3,250
82,55
2.350
59,69
**23 - 38
5.687
144,45
4.250
107,95
3.250
82,55
26 - 32
5.875
149,23 4.000
101,60 2.970
**26 - 32
5.875
149,23
5.000
127,00
3.938
100,03
32 - 38
5.687
144,45
4.000
101,60
2.970
75,44
32 - 44
5.468
138,89 2.750
69,85
1.830
46,48
43 - 44
5.468
138,89
3.250
82,55
2.350
59,69
26.4 - 33.7
6.375
161,93
2.750
69,85
1.830
46,48
1,920
48,77
1.927
48,95
26.4 - 33.7
6.375
161,93 3.250
82,55
2.350
59,69
26.4 - 33.7
6.375
161,93
4.000
101,60
2.970
75,44
33.7 - 39
6.180
156,97
3.250
82,55
2.350
59,69
33.7 - 39
6.250
158,75 4.000
101,60 2.970
36 - 47
8.420
213,87
6.000
152,40
4.400
111,76
4.860
123,44
36 - 59.4
8.120
206,25
3.250
82,55
2.350
59,69
111,76 4.860
123,44
75,44
75,44
36 - 59.4
8.120
206,25 4.000
101,60 2.970
75,44
36 - 59.4
8.120
206,25
5.000
127,00
3.850
97,79
**36 - 59.4
8.120
206,25
6.500
165,10
5.000
127,00
40 - 53.5
8.220
208,79 6.000
* thread type and size control Seal Unit ID
** Available in RATCH-LATCH® Style Only
142
Seal
bore ID
9.5 - 12.6
**20 - 26
6.625
Packer
OD
152,40 4.400
Table 12.4A — RTTS Packers
Casing
OD
(in.)
Casing
Wt
(lb/ft)
Nominal
Tool OD
( in.)
Min.
ID
(in.)
Casing
OD
(in.)
Casing
Wt
(lb/ft)
Nominal
Tool OD
( in.)
Min.
ID
(in.)
2 3/8
4.6
1.81
.60
6 5/8
24 - 32
5.43
1.90
2 7/8
6.4
2.22
.75
6 5/8
17 - 20
5.65
2.40
2 7/8
7.9 - 8.7
2.10
.60
7
32.38
5.65
2.40
3 1/2
5.7
2.93
.62
7
49.5
5.25
2.00
3 1/2
9.2 - 10.2
2.70
.62
7 5/8
20 - 39
6.35
2.40
3 1/2
13.3
2.50
.62
8 5/8
24 - 49
7.31
3.00
4
9.5 - 11.6
3.18
1.12
9 5/8
29.3 - 53.5
8.15
3.75
4
12.5 - 15.7
3.06
.865
9 5/8
40 - 71.8
7.80
3.00
4 1/2
9.5
3.79
1.80
10 3/4
32.75 - 51
9.30
3.75
4 1/2
15.1 - 18.1
3.55
1.51
10 3/4
55.5 - 81
8.85
3.75
4 1/2
11.6 - 13.5
3.75
1.80
11 3/4
38 - 54
10.20
3.75
5
21
3.75
1.80
11 3/4
60 - 71
10.10
3.75
5
23
3.75
1.80
13 3/8
48 - 72
11.94
3.75
5
15 - 18
4.06
1.80
13 3/8
72 - 98
11.50
3.75
5
11.5 - 13
4.25
1.80
16
109 - 146
13.62
3.75
5 1/2
23 - 26
4.25
1.90
16
65 - 109
14.18
3.75
5 1/2
20 - 23
4.38
1.80
18 5/8
78 - 118
16.87
3.75
5 1/2
13 - 20
4.55
1.80
20
94 - 133
17.87
3.75
6
15 - 23
5.06
1.90
20
169 - 204
17.25
3.75
Table 12.5A — Maximum Pressure Differentials for RTTS Packers
Maximum Pressure Differential (psi) at Temperature
Casing Size,
OD, in.
180°F
250°F
325°F
400°F
2 3/8 - 5 1/2
10,000
10,000
10,000
10,000
6 5/8 - 7 5/8
10,000
10,000
10,000
10,000
8 5/8 - 9 5/8
10,000
10,000
8,000
7,000
10 3/4 - 13 3/8
7,500
5,000
3,000
no data
16 - 20
5,00
5,000
3,000
no data
143
FRACPAC COMPLETION SERVICES
Table 12.6A — CHAMP Packers
Casing Size, OD
(in.)
Casing Wt. Range,
(lb/ft)
4 1/2
9.5 - 10.5
5
23
4 1/2
Nominal Tool OD,
(in.)
Min. Tool ID,
(in.)
3.98
1.80
11.6
3.84
13.5
3.75
5
11.5 - 15
5 1/2
26
1.80
4.18
1.80
5
18 - 21
3.98
1.80
5 1/2
13 - 20
4.57
2.00
5 1/2
20 - 23
4.40
1.80
6 5/8
28 -32
7
41 - 49.5
5.25
2.00
7
17 - 38
5.65
2.37
7 5/8
20 - 39
6.35
2.37
9 5/8
29.3 - 43.5
8.15
2.87
9 5/8
40 - 71.8
7.80
2.87
10 3/4
55.5 - 81
8.85
3.00
11 3/4
38 - 71
10.10
3.00
13 3/8
48 - 72
11.94
3.75
13 3/8
72 - 98
11.50
3.75
7
17 - 38
5.65
2.37
7 5/8
20 - 39
6.35
2.37
9 5/8
29.3 - 53.5
8.15
2.87
9 5/8
40 - 71
7.80
2.87
Table 12.7A — Maximum Pressure Differentials for CHAMP® Packers
Casing Size,
OD, in.
144
Maximum Pressure Differential (psi) at Temperature
180°F
250°F
325°F
400°F
4 1/2 - 5 1/2
8,400
8,400
8,400
8,400
7 - 7 5/8
10,000
10,000
10,000
10,000
9 5/8
10,000
10,000
8,000
7,000
13 3/8
7,500
5,000
3,000
no data
Chapter 13
INTRODUCTION
FracPac operations use extensive amounts
of surface equipment that must be
transported to the jobsite and prepared
for operation. The amount and type of
equipment that is selected to perform
the job is determined by considering
the well location, site accessibility, rig
floor space, weight restrictions, and
general downhole conditions of the
well to be treated.
Equipment used to perform FracPac
Completion Services can generally be
divided into functional categories such
as fluid-preparation systems, pumping
equipment, proppant storage and
delivery systems, data acquisition and
analysis hardware, and fracture design
and analysis software.
Halliburton offers a complete selection
of equipment necessary to meet all the
specific job requirements of FracPac
Completion Services.
FLUID PREPARATION
SYSTEMS
Proper preparation of the fracturing-fluid
systems is critical to the effectiveness of
FracPac techniques and is one of the
most equipment-intensive operations
performed at the wellsite. Special filtration systems and blending and mixing
equipment must be delivered, setup, and
checked for proper operation before
preparing any fluids or additives.
Filtration Equipment
Fluid filtration is recommended before
any gravel-pack treatment is performed.
Any solids or microgels that may be
present in the fluid system must be
removed. If these substances are not
removed from the gel fluid system,
formation permeability could be
damaged in the near-wellbore region,
which, in turn reduces well productivity.
Surface
Equipment
For many FracPac operations, filtration
of fluids has not been given high
priority, since the fracturing and
packing techniques resulted in larger
exposed areas of the formation face and
thus less drawdown at the wellbore.
Some damage at the fracture face and
to the proppant pack was expected and
could be tolerated. A certain amount of
tolerated formation damage was caused
by the inordinate amount of time
needed to filter large volumes of gelled
fluids. It is, however, recommended
that the brine used as source water be
filtered before mixing with gel
polymer. Also, all fluids used for gravel
packing and well completion should be
filtered to minimize any damage to the
immediate-wellbore region.
For most gelled fluids, a two-pod,
cartridge-type filter unit provides an economical solution for filtering unwanted
solids as small as 10 microns. Fluids that
are not yet gelled should be processed
through a 2-micron filter if possible.
The body of the filtration unit should
be constructed of stainless steel to
minimize the introduction of corrosion
products to the fluid systems.
Diatomaceous earth filter systems and
systems designed to handle high pressure
are available for special requirements.
The cost associated with using diatomaceous and high-pressure filter systems
usually restricts them to use in large
volumes of ungelled brines.
145
FRACPAC COMPLETION SERVICES
Data Acquisition
Job Monitoring
Digital Densometer
Flow Meter
W
Dry Sand Addition
ell Returns
Fluid
Source
Halliburton 6x5
Centrifugal Pump
To Work
String
Hi
gh
Pr
es
su
re
Di
sc
ha
rge
Recirculating
Loop
Pressure
proppant settling in the tanks, mechanical agitators with
four stainless-steel mixing blades cycle continuously while
proppant is present. These agitators are also hydraulically
driven, which allows variable speed control. Variable
speed control allows the agitator to turn slow enough to
avoid air entrainment in the fluids being mixed. Optional
configurations of this batch-mixing system are available
for smaller operations, one with two 20-bbl stainless-steel
tanks and the other with two 15-bbl crosslinkedpolypropylene tanks.
Recommended mixing procedures for batch-mixing
equipment are to mix the proppant at high
concentrations, typically 12 to 16 lb/gal, and dilute the
mixture with clean gel while pumping. This dilution
process helps obtain the required downhole proppant
concentration.
HT-400 Pump Unit
Constant-Level Additive Mixer (CLAMTM)
CLAMTM
Figure 13.1 — The
blender processes a constant level
of even low-concentration proppants such as those that are
pumped in early stages of a FracPac treatment. This blender is
very accurate and economical.
MIXING AND BLENDING EQUIPMENT
Mixing and blending equipment for FracPac Completion
Services is available in a variety of types and sizes. Each
size and type of system is designed to perform in different
conditions and applications. Batch-mixing systems are
available for smaller operations. Constant-level additive
mixers provide the capability for jobs with low pumping
rates or low proppant concentration. Continuous blending
systems provide complete mixing and delivery systems
that handle proppants, liquid additives, and dry additives.
Batch-Mixing Systems
Batch-mixing systems can be configured many different
ways. For smaller operations, a standard skid-mounted
unit can provide very economical mixing capability.
Larger jobs can be performed with additional units added
to the system, but space and weight requirements soon
govern and may preclude the use of this type of system.
The standard batch-mixing system is configured with two
25-bbl stainless-steel mixing tanks, and two hydraulically
driven centrifugal pumps. Hydraulic drive on the pumps
allows speed control from 0 to 1,500 rev/min. To prevent
146
The constant-level additive mixer is an ideal choice for
FracPac jobs in which low rates or low proppant
concentrations must be pumped. Refer to Figure 13.1 for
a schematic of this blender system. Low pumping rates,
from 3 to 10 bbl/min, can be pumped with this mixer,
which restricts its use in some fracturing applications but
makes it very economical for others. The constant-level
additive mixer can be used to mix the lowerconcentration proppants that are pumped earlier in the
job, and a batch mixer can be used to mix the higherconcentration, tail-in proppants pumped at the end of
the job. This technique works well for FracPac and
gravel-pack treatments with small total volumes.
Continuous Blending Equipment
Halliburton has a wide range of fracturing blenders
available for use in FracPac Completion Services,
fracturing services, and gravel-pack services. Units capable
of handling pumping rates from 3 to 100 bbl/min and
proppant concentrations of 1 to 18 lb/gal are currently in
use. Most of the continuous blending systems have been
trailer-mounted for land operations and skid-mounted
for offshore operations.
With increasing demand for fracturing operations in
high-permeability formations and the development of
FracPac Completion Services, Halliburton has designed
and built a continuous blending system specifically for
offshore services of this nature. This new blending system
will meet the following specifications:
• The blender meets ISO package specifications with
DNV capability (8 ft wide x 8.5 ft high x 20 ft long).
• Weight distribution complies with 500 lb/ft2 supplyvessel deck load limit.
• Configuration allows vessel offshore platform
operation.
• Power package is self-contained.
• Power unit is air started, diesel powered, and radiator
cooled.
• Liquid additives, dry additives, and tub agitation are
hydraulically powered.
• Remote control is completely automatic, with manualoverride backup system for offshore operations.
• Electrical systems are corrosion-proof.
• Suction and discharge pumps have individual, hydraulically driven speed controls.
• Flow rates from 4 to 40 bbl/min at proppant
concentrations of 0.5 to 18 lb/gal
• Proppant delivery is a maximum of 240 sacks/min.
• Additive pumps are automatically controlled and as
many as five pumps can be in the system.
• Additive pumps are available to cover a wide range of
rates and job requirements.
• Dry additive systems are automatically controlled and
as many as three can be used in the system.
• Dry additive systems can be selected for low-concentration additives such as breakers or high-concentration
additives for fluid-loss control.
• The blender uses a vertical, cylindrical tub of 4-bbl
capacity with discharge pump mounted immediately
beneath the tub to minimize air-entrainment problems
in high-viscosity gel systems.
• The blender weight conforms to worldwide lifting
limits of 10 tons, and it can be compartmentalized.
• The blending system was specifically designed for
FracPac Completion Services and should simplify the
choice of equipment for such services.
HIGH-PRESSURE PUMPING EQUIPMENT
Most FracPac Completion Services operations call for the
highest injection rate and the highest proppant concentration possible for the specific well conditions. Job histories
have recorded most FracPac injection rates at 12 to
25 bbl/min. With injection rates such as these and with
stringent space and weight limitations, high-horsepower
pumping units are recommended for FracPac operations.
All equipment designed for FracPac applications can
withstand the sustained high injection rates and high
proppant concentrations encountered.
For land operations, the nearest available standard
fracturing unit can be used to perform FracPac jobs. In
offshore applications, skid-mounted units are usually the
pumping equipment of choice if a dedicated stimulation
vessel cannot be obtained.
Halliburton offers a wide array of pumps for fracturing
operations. Selection of the pumping equipment that is
best suited to the job depends on the anticipated pumping
pressures, injection rate, total pumping time, and
economics. Most FracPac operations involve pumping
durations that are very short and an injection pressure
between 2,000 and 7,000 psi.
The pump recommended for FracPac applications, such
as the one mentioned in the previous paragraph, is one
that has performed faithfully in stimulation and cementing
services since 1957. This horizontal triplex pump
(HT-400) began with a 400-horsepower rating and has since
been constantly improved to yield an 800-horsepower
rating that sets the standard in the oilfield industry. The
HT-400 has been the preferred pump for well control and
relief-well pumping for major blowouts and emergencies.
The mechanical integrity of these pumps makes them first
choice for FracPac applications, since there is no margin
for error while pumping small volume treatments. With
total pumping time at only 10 to 30 minutes and the
requirements of the tip-screenout technique, pumping
equipment must be failure-free. Since fluid efficiencies are
usually very low with FracPac applications any shutdown
caused by equipment failure would most likely end the
treatment. Either redundant equipment should be on site,
which is costly, or the primary pumping equipment must
be reliable. If higher pump rates or limited space for
placement is a requirement, the quintaplex pump (HQ)
is recommended, since it can achieve up to 2,000 hhp.
Operating systems for pumping equipment range from
pneumatic control to microprocessor-driven, automatic
remote control. Job requirements and equipment
availability govern the selection of pump operating systems.
147
FRACPAC COMPLETION SERVICES
Discharge Hoses
Special high-pressure hoses are used to transmit fluids from
the pumps to the wellhead. Offshore operations require
that a flexible, high-pressure hose be used for vessel-toplatform pumping. A hydraulic disconnect is also mandatory
to allow the stimulation vessel to disengage from the rig or
platform in an emergency. Backpressure valves isolate the
wellhead pressure if the vessel needs to disengage.
Crew's
Quarters
and
Wheelhouse
Observation Deck
and
Control Room
Downhole Pump Suction and Discharge Manifolding
Downhole Pumps High Pressure
Downhole Pumps High Pressure
Downhole Pumps High Pressure
Downhole Pumps High Pressure
Downhole Pumps High Pressure
Platform Rig Up
Blender bypass
3 1/2 in. IF Tubing with
full-opening TIW valve
Downhole Pumps High Pressure
Rig
manifold
to casing
Downhole Pumps High Pressure
Electronic
Pressure
Transducers
Proportioning
Blender
High-Pressure
Regulating
Pop-Off Valve
Flow Meter
Radioactive
Densometer
High-Pressure
Discharge
Line to annulus
Halliburton
Lo Torc
Valve
Check Valve
High-Pressure
Discharge
Line to tubing
Downhole Pumps High Pressure
Rig
Pump
Gel feed line
from below
deck storage
Sand
Tank
gel feed line
from below
deck storage
High-Pressure
Regulating
Pop-Off Valve
Offshore
Stimulation
Vessel
High-Pressure Discharge
Line from Offshore Vessel
Hydraulic
Quick
Disconnect
Pumping rates determine discharge line size. For rates of
10 bbl/min and higher, a 3-inch Coflexip hose is recommended. For pumping rates below 10 bbl/min, a 2-inch
Coflexip hose is recommended.
PROPPANT STORAGE AND DELIVERY
Proppant supply to the blender during fracturing operations
is critical. A storage and delivery system is necessary to
maintain a constant flow of proppant to the blender. Bulk
delivery of proppant to the wellsite for land-based FracPac
jobs is performed with covered dump trucks. Proppant
transport from the dump trucks to the blender is then
continued by pneumatic systems or conveyor belts.
Offshore proppant storage and delivery, however, presents
other challenges. Space, weight, and height limitations
must be considered when planning offshore operations.
On fixed platforms, height of stored proppant is not as
critical a concern as it is on stimulation vessels where the
center of gravity must be kept low. Storage of proppant
on platforms is usually in vertical silos with flow-control
gates. Maximum size of these silos is location dependent,
but typical silos hold 300 ft3 to 700 ft3.
In stimulation vessels, proppant can be stored in several
bins and connected by a common conveyor system to the
blender. Long-term location of such bins and conveyor
systems should be on the lower deck of the stimulation
vessel, whereby the center of gravity is lowered. Figure
13.2 shows a schematic of offshore-vessel and platform
equipment placement.
High-Pressure Discharge Line to Platform
Figure 13.2 — The layout of the stimulation equipment on
vessels and platforms for offshore FracPac and gravel-pack
treatments is critical. On vessels especially, horizontal and vertical
weight distribution affects the center of gravity. Equipment
placement on platforms is crucial for personnel safety and
efficient working conditions.
148
Most Halliburton blender systems use automatically
controlled and calibrated sand screws that regulate the
flow of proppant to the blender tub. This system has
gained worldwide acceptance through many years of use in
fracturing operations. Alternate delivery systems, however,
are being considered for offshore operations where space
and weight must be minimized. Such delivery systems use
automatically controlled, calibrated gates to regulate
proppant flow rates by changing the flow area of the gate.
Effectiveness of the proppant delivery systems can be
measured by a radioactive densometer located in the
discharge line. This densometer allows adjustments to be
made to the proppant flow during fracturing operations.
DATA ACQUISITION AND
ANALYSIS SYSTEMS
When performing fracturing treatments, the surface treating
pressures of the workstring and annulus, the downhole
pumping rate, and the proppant concentration should be
monitored and recorded. Data acquisition systems perform
the monitoring and recording functions. Halliburton uses
one of three data acquisition systems, depending upon what
is needed for the particular job. Two of the three systems
are PC-based, and the third runs on a minicomputer.
Portable Surface Data System
The portable surface data system is a PC-based, portable
data acquisition system mounted in a ruggedized case.
The data acquisition system provides the following:
• Inputs are available for three pressures, three flow rates,
one density, and one temperature.
• A local-area network (LAN) connection that allows
simultaneous data acquisition from UNIPRO data
acquisition systems is mounted locally on the
equipment.
• An overhead display is provided for numerical data
acquired during treatment. A strip chart plot of critical
job parameters is made in real time during the
treatment.
• Standard ASCII format, IBM-compatible data can be
output to 3-1/2-inch diskettes for transport and detailed
posttreatment analysis.
For treatments where surface data monitoring is sufficient,
the COMPUPAC system provides very reliable, economical
data acquisition. This system can be complemented with
a display on the rig floor at wellsites where access to the
stimulation vessel is limited. Company personnel can
then monitor the job at the rig.
Surface and Bottomhole Data System
The surface and bottomhole data acquisition system is
also a PC-based system. This system has been expanded to
allow up to two additional monitors for the display of real-
time surface data and calculated bottomhole data in either
numerical or graphical format. Acquisition capabilities are
identical to the surface data system, but the capability to
calculate bottomhole treatment pressure allows real-time
decisions and adjustments to be made during the treatment.
With a simple modification, the surface and bottomhole
data system can transfer data to a second PC where input
is made to software such as FRACPRO, to model and
evaluate the treatment in real-time. The surface and
bottomhole data system requires a larger, sheltered area
for setup and operation.
Technical Command Center
The Technical Command Center is a minicomputer-based
acquisition and control system. This system provides data
acquisition, real-time data analysis, and direct control of
automatic, remote-control pumping and blending equipment. The Technical Command Center is one of the
most advanced systems in the well-stimulation industry
and offers the following features:
• Monitors and records more than 1,200 surface treatment
parameters including injection rates, additive rates, slurry
density, pressures, material inventories, and equipment
operating status.
• Communicates with a wireline computer logging
system via an RS-232 serial port to monitor bottomhole
treating pressures and other parameters during the
treatment. These data can then be used to analyze the
treatment in real time.
• Monitors real-time minifrac data to provide critical
onsite fracturing parameters and, if necessary, data to
redesign the fracture treatment.
• Displays the log/log plot of the net bottomhole treatment
pressure versus time, to make real-time adjustments to
the fracturing treatment.
• Transfers data to a PC if necessary, to interface with
stimulation software such as FRACPRO. Technical
Command Center fracture design software and
FRACPRO can be used in combination to assist in
real-time fracture analysis.
• Transfers treatment data via satellite to the Halliburton
Technology Center, allowing additional stimulation
experts to use design/analysis software real time and
make difficult decisions real time, if necessary.
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FRACPAC COMPLETION SERVICES
FRACTURE DESIGN AND
ANALYSIS SOFTWARE
Many forms of software for fracture design and analysis
are available. Traditionally, Halliburton has developed its
own advanced fracture-design software; however, advances
in PC technology have made other software resources
available for reliable fracture design. So many programs
exist for fracture design that it is not within the scope of
this publication to discuss them all. Two programs have
been tested and proven reliable for FracPac Completion
Services. These programs are FRACPAC and FRACPRO.
A third program, STIMPLAN, has also been used for
fracture design of high-permeability formations. Although
these programs are part of the equipment at the jobsite,
their complexity merits a separate discussion. These fracture
design packages are discussed in detail in Fracture Design
Simulators (Chapter 7).
RESERVOIR DESIGN SIMULATORS
Although not part of the equipment that is transported
and used at the jobsite, reservoir simulator and well-test
design and production simulator software packages are
very much a part of the equipment used to design and
evaluate the effectiveness of FracPac Completion Services.
The reservoir simulator used for FracPac Completion
Services is RTZ, and the well-test design and production
simulator is RESULTS.
• Partially penetrating wells
• Radially composite reservoirs
• Horizontal wells
• Closed chamber tests
• Single-well, vertical pulse tests
• Combinations of the above
RTZ can be configured with radially composite geometry
to model a deep damage zone or a zone near the wellbore
with impaired permeability caused by sand production. By
running the simulator in constant-rate mode, the user can
design a well test that will help characterize the permeabilityimpaired zone. Constant-pressure production can be
simulated to generate a production-decline curve for the
well with a permeability-impaired zone.
Factors such as a vertical fracture or fracture-face damage
can easily be incorporated into the radially composite
model. A sensitivity study can be performed based on
expected production to optimize the fracture design before
the stimulation is performed. Also, RTZ can be run in
constant-rate mode to design a well test that will evaluate a
FracPac stimulation treatment. A more detailed discussion
of the reservoir simulator and reservoir-engineering aspects
of FracPac Completion Services can be found in Reservoir
Engineering (Chapter 4) and Well Testing (Chapter 5).
RTZ Reservoir Simulator
Halliburton uses the RTZ simulator to model threedimensional flow of single-phase oil, gas, or water within
the wellbore environment. The simulator uses a cylindrical
coordinate system. Either constant-rate mode can be
chosen to simulate a well test, or constant-pressure mode
can be chosen to yield a production decline curve. In
addition to the simulator’s standard features, the model
includes
• Wellbore storage (may change with respect to time)
Halliburton also uses RESULTS, a well-test design and
production simulator package that runs in a WindowsTM
(a trademark of Microsoft Corporation) environment on a
personal computer. This program allows the user to design
well tests by inputting the well and reservoir characteristics,
generating simulation data, and producing plots of the
generated data.
The model can simulate
RESULTS has extensive pressure-behavior modeling
capability. Simulations of drawdown-buildup tests,
injection-falloff tests, drillstem tests, interference tests,
and closed-chamber tests can be performed. Also, decline
curves can be generated. The modeled reservoir parameters
can be configured with
• Multilayered reservoirs
• Homogeneous or dual-porosity
• Hydraulic fractures with uniform or variable conductivity
• Vertical or horizontal well orientation
• Variable skin (different skin values for different
formation layers may change with respect to time)
• Turbulent flow
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RESULTS Well-Test Design and
Production Simulator
• Vertical wellbores can be fully penetrating, partially
penetrating, or fractured.
• Outer boundary can be infinite, circular, or composed
of one or two nearby boundaries.
• Boundaries can be a mixture of no-flow and constantpressure.
• Composite reservoir or dual-permeability reservoir
• Up to 10 layers with different reservoir and well
conditions for each layer.
One model available in RESULTS that is particularly
applicable to FracPac Completion Services is the radially
composite reservoir that contains a vertical fracture of
finite conductivity. This model is a new analytical solution
to a problem that was previously restricted to numerical
simulator modeling. Analytical solution offers an advantage
in speed over numerical solution when multiple sensitivity
studies are performed.
The RESULTS simulator can be run in constant-rate mode
to design well tests for wells with near-wellbore damage
or formation sanding problems. Parameters from the well
test can be used to characterize the permeability-impaired
zone and the unaltered reservoir. This information can
then be input to the simulator (now running in constantpressure mode) to generate a production-decline curve.
Performing sensitivity analyses on various fracture lengths
and conductivities can help the stimulation treatment to
yield maximum production within operational constraints
and budget. After the well has been stimulated and allowed
to produce, the RESULTS simulator can again be used
to design a well test for a fracture of finite conductivity
in a radially composite reservoir. The results of this type
of well test can help evaluate the effectiveness of the
FracPac treatment.
Case Histories (Chapter 16) reviews some selected FracPac
case histories that simulator predictions can use as reference
points to prove and improve accuracy.
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FRACPAC COMPLETION SERVICES
152
Chapter 14
INTRODUCTION
This chapter focuses on the wellsite tasks
performed by Halliburton during a
typical FracPac Completion Service or
gravel-pack job. The effectiveness of the
stimulation and sand-control job relies
on the preparation and setup of equipment, and operational safety while
operating that equipment. All aspects
of the job, from rig-floor equipment,
pumping equipment, downhole tools,
fracturing and carrier fluids to proppants
play a critical role in whether the
stimulation is effective. The following
categories contain concerns that may
be used as a checklist.
SURFACE EQUIPMENT
CONCERNS
The Rig-Floor Equipment
Layout
The rig floor, whether on a land rig or
an offshore rig, is the center of activity
for operations on the well. Walkways
must be left free of obstructions during
the job for operating personnel to
monitor job functions and make adjustments to equipment stationed on the
rig floor. Great care should be taken
not to jeopardize personal safety of
anyone required to be on the rig floor.
The following guidelines should be
followed when setting up and operating
the surface equipment on the rig floor.
____ Discharge lines should be located
so that fluid path is optimum
for injecting fluids down the
workstring or down the annulus
to reverse.
____ A high-pressure manifold
should be connected to the sur-
face equipment to allow fluids to
be pumped in any combination
of paths by opening and closing
the appropriate valves.
____ Full-opening valves should be
mounted in any line through
which high flow rates will be
pumped. The full-opening valves
impose minimum restriction to
fluid flow.
Job
Procedures
and Best
Practices
____ The return line from the manifold to the rig tanks should have
an adjustable choke to regulate
return rates while circulating or
reversing the slurry flow. The
discharge of this line should be
visible so that it can be monitored for potential problems
during the treatment.
____ Flow meters should be mounted
in both the injection and
return lines.
____ A densometer should be used to
measure proppant concentration in both the injection and
return lines.
____ Pressure transducers at the
wellhead should be positioned
so that both the workstring and
the annulus can be monitored.
____ The workstring should have a
minimum of two transducers
active at all times.
____ All personnel with responsibilities
on or near the rig floor should be
within view of pressure readings,
and preferably pump-rate and
proppant-concentration readings,
or be in direct radio contact with
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FRACPAC COMPLETION SERVICES
the treatment operator. This guideline enables rigfloor personnel to be aware of the job sequence.
____ The layout of lines and other equipment on the rig
floor should be organized with minimum line length
and line contact. An unobstructed path for foot
traffic should be available to allow all personnel to
access valves and perform other job functions.
____ All personnel not essential to pumping operations
should stay clear of the injection and return lines
on the rig floor during pumping.
____ If a crossover tool is used in the toolstring, it
should be able to withstand the high flow rates
associated with FracPac services.
____ Blank pipe used should be able to withstand
screenout pressures.
____ The gravel-pack packer should be able to withstand
high differential pressure when screenout occurs.
____ Potential tubing contraction should be calculated
during the job. Tubing-string movement should
be estimated and precautions should be taken to
prevent such movement.
Equipment
Equipment setup is essentially the same for FracPac
service as it is for a conventional fracture stimulation.
The following special concerns apply to FracPac jobs.
____ Proppant concentrations are unusually high
compared to conventional fracturing jobs.
Ensure that suction-hose lengths connected to
high-pressure pumps are a minimum length.
Fracturing Fluids
The effectiveness and efficiency of a FracPac stimulation
relies on the quality of the fracturing fluids used to perform
the procedure. Special care should be taken when handling
and mixing fluids. The following concerns should be
applied to protect fluid quality.
____ The cleanest base fluid possible should be used.
____ Sudden pressure increases can occur when
performing tip-screenout fracturing. Premature
screenout and/or fracture-entry restrictions are the
primary causes for a sudden increase. All personnel
should be aware of this possibility.
____ A high-rate pressure-release valve should be
installed on the discharge line. The release line from
the pressure-release valve should be strategically
positioned and restrained so that personnel are not
endangered should a pressure discharge occur.
____ For offshore operations, when pumping equipment
is on a boat, a quick disconnect should be installed.
The vessel can then release the discharge line
and disconnect from the rig in an emergency.
A backpressure valve should also be installed to
prevent line discharge if an emergency disconnect
is necessary.
____ Holding tanks should be inspected for cleanliness
before adding base fluids. Substances such as rust,
dirt, drilling mud, and old gel residue compromise
fluid performance.
____ Each tank should be treated with biocide before
the base fluid is added.
____ Pilot tests of the designed fracturing fluid should
be conducted on location before preparing bulk
quantities of fluid. Fluid properties such as viscosity,
pH, break time, and crosslink time should be
identified. Confirming tests should be performed
after the fluid is prepared.
DOWNHOLE CONCERNS
____ Whenever possible, liquid gel concentrate (LGC)
should be used to avoid lumping problems
associated with unhydrated, powdered gel.
Downhole Tools
____ Shearing and filtering fluids should be considered
in applications where ultraclean fluid is required.
Downhole tools must withstand higher pressures during a
FracPac job than during a conventional fracture stimulation. The following concerns apply to downhole tools used
to perform FracPac jobs and are checked by Halliburton.
154
____ All base fluids should be filtered through a
10-micron filter or smaller.
Proppants
____ Proppants should be checked for proper type and
size, and meet API specifications. Sieve analyses
from each container should be used to establish size
and fines content.
GENERAL JOB SEQUENCE
The general job sequence progresses differently for FracPac
applications where mechanical sand control equipment is
placed in the wellbore than for applications where no
sand control equipment is placed. The main differences
between these two types of jobs is how the tools are
positioned in the hole, and how the annular gravel pack is
pumped after tip screenout has occurred in the fracture.
Jobs with Mechanical Gravel-Pack
Equipment (FracPac)
On jobs where gravel-pack equipment such as screens and
blanks is to be set, the following sequence should
generally be followed:
1. Retrieve perforating guns from the well after perforating.
2. Run the completion assembly into the hole.
3. When on depth, set the gravel-pack packer and reciprocate the workstring to set the multiposition tool in
circulating position. Circulate completion fluid into
the well to fill the annulus between casing and
workstring with a fluid of known density.
4. Shut in the annulus and position the valve so that fluid
can be pumped down the workstring while monitoring
annulus pressure.
5. Pressure test all lines to 1,000 psi over the anticipated
maximum job pressure.
9. Perform a minifrac test by pumping the proposed
fracturing fluid at a constant rate. A step-down test can
be performed as part of the minifrac test to determine
whether any fracture-entry restrictions are present.
10. Displace the minifrac fluid and shut down the pumps
immediately. Monitor the pressure decline until
fracture closure is observed.
11. Calculate the fluid-leakoff coefficient, closure pressure,
closure time, fluid efficiency, and friction pressure.
Refer to Chapter 8 for the procedures involved in
determining these coefficients and pressures.
12. Design a propped-fracture treatment that optimizes
pumping rate, pad volume, and proppant schedule.
13. Perform the tip-screenout fracture treatment until
screenout occurs or until the volume needed to form
an annulus pack remains in the workstring.
14. Slow the pumping rate to 1-2 bbl/min and open the
annulus valve through a choke. This choke allows the
proppant pack to be dehydrated across the screen,
forming an annular pack between the casing and screen.
15. Shut down the pumps when maximum pressure is
achieved. Observe the pressure bleedoff. Restress
the pack until a tight annulus pack is achieved. A
“top off” gravel pack can be added, if necessary.
16. Reciprocate the workstring to select the reverse
position on the multiposition tool. Reverse any
excess slurry from the workstring.
17. Retrieve the workstring from the hole and run the
production tubing and assembly into the well.
18. Clean up the well slowly to allow the gravel pack
to stabilize.
6. Perform the step-rate test by pumping completion fluid,
if possible. The step-rate test should pump a pressure
high enough to exceed the formation fracture gradient.
A friction-reducer additive may be necessary to reduce
wellhead pressure while pumping higher rates.
7. Shut down the pumps and allow the pressure to return
to near-initial reservoir pressure.
8. Evaluate the step-rate test to determine the fractureextension pressure.
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FRACPAC COMPLETION SERVICES
Jobs Without Mechanical Gravel-Pack
Equipment (OptiPac and OptiFrac)
On jobs where no mechanical gravel-pack equipment
is placed in the well, the following job sequence
generally applies:
1. Retrieve perforating guns from the well after perforating.
2. Run tubing string with an open-ended packer into the
hole and set at desired depth.
3. Pressure test all lines to 1,000 psi over maximum
anticipated job pressure.
4. Pressure the annulus and monitor that pressure
throughout the fracturing job.
5. Perform the step-rate test by pumping completion
fluid, if possible. The step-rate test should pump a
pressure that exceeds the formation fracture gradient.
A friction-reducer additive may be necessary to reduce
wellhead pressure while pumping higher rates.
6. Shut down the pumps and allow the pressure to
return to near-initial reservoir conditions.
7. Evaluate the step-rate test to determine the fractureextension pressure.
8. Perform the minifrac test by pumping the proposed
fluid for a propped-fracture treatment at a constant
rate. A step-down test may be performed as part of
the minifrac test to determine if any fracture-entry
restrictions are present.
9. Displace the minifrac fluid and shut down the pumps
immediately. Monitor the pressure decline until fracture
closure is observed.
10. Calculate the fluid-leakoff coefficient, closure
pressure, closure time, fluid efficency, and friction
pressure. Refer to Chapter 8 for procedures used to
determine these coefficients and pressures.
11. Design a propped-fracture treatment that optimizes
pumping rate, pad volume, and proppant schedule.
12. Pump the tip-screenout fracturing treatment until
screenout occurs.
156
13. Shut down the pumps when maximum pressure is
reached and allow the fracture to close and the
proppant to stabilize in the fractures.
14. Clean up the well slowly to allow the fractures and
proppant to stabilize.
Chapter 15
INTRODUCTION
Following FracPac stimulation, wireline
logs can be run to help evaluate treatment effectiveness. Logs can determine
the height of hydraulically induced
fractures, verify the placement of pack
materials, and analyze flow from treated
formations. Tracer and production logs
are the wireline services most commonly
used for FracPac evaluation.
VERIFYING PLACEMENT OF
PUMPED MATERIALS
To verify the placement of pumped
materials such as fracturing fluid,
proppant, and gravel, spectral gamma ray
tools such as Halliburton’s TracerScan
tool are used. The materials to be
pumped are tagged with radioactive
tracers that have dissimilar gamma ray
spectra. Each tracer emits gamma rays
of different energies and different
intensities than the other tracers. In a
FracPac job, the fracturing fluid may
be tagged with one tracer, the proppant
with a second tracer, and the gravel with
a third tracer. Since the TracerScan tool
can distinguish gamma rays in different
energy ranges, it can differentiate the
tracers after they have been pumped
downhole during FracPac operations.
TracerScan logs record spectral gamma
ray data as a function of depth and
therefore can evaluate the vertical
distribution of the tagged materials. This
allows the total and propped fracture
heights to be estimated and voids in
gravel packs to be located. TracerScan
data also give information regarding the
approximate radial location of tracers and
permits tracers in the borehole to be distinguished from tracers in the formation.
TracerScan logging is different from
nonspectral tracer logging because
TracerScan logging depends upon tracers
with different gamma ray spectra rather
than on tracers with different half-lives.
A TracerScan log can be run on a single
trip to the well immediately after
FracPac pumping operations have been
completed. This contrasts with the
traditional nonspectral tracer logging
that required several trips to the well
days, weeks, and even months after the
pumping operations.
Evaluation
Logging
TracerScan Job Design
Job design should involve the operating,
pumping, tagging, and logging
companies. The pumping program
must be outlined, the information to be
obtained from logging must be specified,
and the tracers that will best meet the
logging objectives must be selected.
Tracer Selection
Tracer properties that must be
considered in selecting tracers for a
FracPac job include energy levels,
spectral peaks, half-lives, and concentrations. The type and number of tracers
are also important factors.
TRACER ENERGY LEVELS – The distance
that a gamma ray travels through matter
depends upon the gamma ray’s energy
level. High-energy gamma rays travel
farther than low-energy gamma rays. A
tracer is considered to be of low energy
if most of its emitted gamma ray energies
do not exceed 600 keV. Low-energy
tracers are best used in the near-wellbore
region and in tail-in material at the end
of a pumping operation. When tracers
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FRACPAC COMPLETION SERVICES
Table 15.1 — Common Tracers Used in Hydraulic Fracturing
Tracer
Isotope
Half-Life
(days)
Gold-198
198Au
2.70
Iridium-192
192Ir
Antimony-124
Scandium-46
124Sb
46Sc
74.00
60.20
83.80
are at some distance from the wellbore, high-energy tracers
(those with most gamma ray energies exceeding 600 keV)
are more easily detected than are low-energy tracers. Thus,
high-energy tracers, especially those with energies above
1,000 keV, are more suitable for tagging materials used
during the early stages of fracturing operations. Table 15.1
gives energy levels and half-lives of several tracers used in
evaluating fracturing and gravel packing operations.
TRACER SPECTRAL PEAKS – When more than one tracer
is used, the gamma ray spectra of the tracers must be
considered. The major gamma ray peaks in each spectrum
must be sufficiently different from those in the other spectra
so that the tracers can be easily distinguished from one
another. Figures 15.1 and 15.2 show the spectral peaks
of two tracer combinations. One of these combinations is
suitable for TracerScan work, and the other is not.
NUMBER OF TRACERS – In general, the minimum number
of tracers should be used to evaluate the FracPac treatment.
As the number of isotopes that are used increases, it becomes
more difficult to spectrally differentiate the isotopes. It
also becomes more difficult to determine precisely the
concentrations and the radial-distance indicators.
TRACER HALF-LIVES – Tracer half-lives should be long
enough so that if there are reasonable job delays, it should
not be necessary to obtain additional tracers. Tracers with
half-lives on the order of 60 days are commonly used, but
specific jobs may require shorter or longer times.
158
Gamma Ray
Energy
(keV)
Gamma Ray
Intensity
Energy Level
412
0.96
Low energy
676
0.01
311
1.42
468
0.48
603
0.18
606
1.05
720
0.15
1,353
0.05
1,691
0.49
2,091
0.06
889
1.00
1,121
1.00
Low energy
High energy
High energy
TRACER TYPES – In 1992, TracerScan log interpretation
was enhanced by the introduction of zero-wash tracers, also
known as zero-leach tracers. Before zero-wash tracers
became available, tracers were prone to wash off the tagged
material or to plate out on tubular assemblies. This caused
abnormally high tracer concentrations in the borehole. The
new technology has eliminated the wash-off and plating
tendency for solid tracers; however, except for scandium,
liquid tracers still exhibit this characteristic. Nevertheless,
liquid tracers can be used successfully, but it is critical
that the tagging agent be chemically formulated so that
preferential deposition of the tracer will occur in the
formation and not in the borehole.
TRACER CONCENTRATIONS – There is a natural variation
in the intensity of gamma rays emitted by tracers; thus,
TracerScan measurements will exhibit statistical variations.
Tracer concentrations on tagged materials must be high
enough to minimize these statistical variations in TracerScan
measurements but must be low enough to not distort tool
response. Spectral gamma ray tools are designed for a
linear response up to a certain maximum gamma counting
rate (generally between 2,000 and 5,000 API units); higher
rates degrade the response. Tracer injection rates are
commonly a few tenths of a millicurie per 1,000 gallons of
fluid (a few megaBecquerels per cubic meter of fluid, or a
few hundredths of a megaBecquerel per kilogram of solid).
These rates usually result in gamma ray measurements of
a few hundred to a few thousand API units.
Radioactive Tracer Spectra
Radioactive Tracer Spectra
Well-Separated Peaks
Poorly Separated Peaks
192Ir
100
80
60
40
20
192Ir
120
46Sc
Relative Intensity
Relative Intensity
120
131I
100
80
60
40
20
200
600
1,000
1,400
Gamma Ray Energy (keV)
1,800
200
600
1,000
1,400
Gamma Ray Energy (keV)
1,800
Figure 15.1 — Iridium-192 and scandium-46 are an
excellent pair of tracers for use in TracerScan operations
since their spectral peaks are well separated.
Figure 15.2 — Iridium-192 and iodine-131 are not a good pair
of tracers for TracerScan work. Some of the spectral peaks are
not well separated; therefore, the tracers are difficult to
spectrally isolate.
Since the gravel is concentrated in the borehole and the
fracturing fluid and proppant are dispersed in the
formation, care must be taken in selecting the tracers and
their concentrations so that gamma rays from tracers in
the formation are not obscured by gamma rays from
tracers in the borehole. It is also important that the tagged
components of the FracPac job be pumped in a manner
that is representative of the FracPac operation as a whole.
Data Quality Considerations
Table 15.2 shows guidelines for selecting tracers for a
typical FracPac completion.
Several measures can be taken to ensure that the information obtained from TracerScan logs is of the highest
quality possible. In general, these measures increase the
accuracy of measured data and reduce the number of
interpretation possibilities.
First, information from other logs, especially gamma ray
and sonic, is helpful. Although not required, a TracerScan
log can be run before a FracPac job to measure the
background gamma radiation that must be subtracted
from the later tracer measurements. When such a prejob
TracerScan log is not run, the background gamma ray is
estimated from the postjob log.
Table 15.2 — Typical Tracer Design for FracPac Completion
Fracturing Phase
Recommended Tracer
Tracer Form
Tracer Concentration
Pad
Scandium-46
Liquid or
0.4 mCi/1,000 gal
100-mesh zero-wash
(tracer/pad)
particles
Sand to tip screenout
Antimony-124
Zero-wash particles
0.4 mCi/1,000 gal
(or Scandium-46 if
sized to sand size
(tracer/sand)
Zero-wash particles
0.25 mCi/1,000 gal
sized to sand size
(tracer/sand)
pad is not tagged)
Cut crosslinked gel
through pack
Iridium-192
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FRACPAC COMPLETION SERVICES
TracerScan Log
0
Iridium
Gamma
Relative Distance
Far 1000
API
200 Near
Scandium
Relative Distance
Near
Far 1000
Iridium
Formation
API
0
Scandium
Formation
API
0
Collar Locator
1000
Iridium
Formation
API
0 0
Scandium
Total
API
1000 0
Iridium
Total
API
Scandium
Formation
1000
API
0
Scandium
Scandium
Scandium
X600
Iridium
Collar
Locator
Iridium
Iridium
Gamma
X650
X700
X750
160
1000
Next, to reduce the statistical variations associated with the
measurements that are used to calculate the radial-distance
indicator, multiple logging runs should be made over the
zone of interest. Typically, three to five passes are made at
a logging speed of 10 ft/min.
Finally, all information pertaining to the placement operation should be carefully documented. This documentation
should include the planned program and the actual
program. The tracers used, their injection rates, and the
type of tagging agent should be listed.
TracerScan Log Evaluation
For each tracer used, TracerScan logs can display the gross
measured gamma ray count rate, a relative-distance curve,
a borehole component, and a formation component. In
evaluating a TracerScan log run on a FracPac completion,
the relative-distance curves are the most useful. These curves
are used in a qualitative sense, with low values indicating
that the tracer is “near” the borehole and high values
indicating that the tracer is “far” from the borehole.
Figure 15.3 shows a TracerScan log used to determine
the placement of fracturing fluid and proppant.
PRODUCTION LOGGING
Production Logging gives quick and accurate flow information at the wellsite. Reliable results can be obtained in both
single-phase and multiphase flow, whether in vertical or
deviated wells. Production Logging flow profiles can be
used to evaluate the effectiveness of a FracPac treatment
and can diagnose production problems such as leaking
tubulars and crossflow between zones.
Halliburton’s wellsite Production Log Analysis (PLA)
program uses fluid dielectric, fluid density, flowmeter,
temperature, pressure, and optional gradiomanometer data
and gives results identical to those obtained at computing
centers. The program determines average fluid velocity;
oil, gas, and water holdups; and the downhole and surface
volumetric flow rates of the fluid components. Quality
indicators on the PLA log help in judging the correctness
of the calculation models and in optimizing parameter
selections for the calculations.
As shown in Figure 15.4, Halliburton’s production logging
tools can be combined for multiple measurements in a
single logging run. Toolstrings can be run on wireline in
conventional wells and on drillpipe workstring or coiled
tubing in deviated wells. Additional services are available for
confirming, refining, and expanding some of the information provided by the primary services. The additional
services include Borehole Audio Tracer surveys, radioactive
fluid travel logs, and Thermal Multigate Decay logs.
Measuring Fluid Characteristics
Production logging measurements allow analysts to
determine the fluid components that are present in the
flowstream and the velocity of each component.
Fluid Components
Wellbore fluids can be described by the phases, or
components, that are present (i.e., water, oil, and gas). For
a particular phase, the holdup at a given depth in the well
is the fractional cross-sectional area of the pipe occupied
by that phase. The Hydro and fluid density tools provide
the information for calculating holdups. At least one of
these tools is needed to calculate two-phase holdups, and
both tools are required for three-phase calculations. Another
device, the gradiomanometer, can be used in place of the
fluid density tool.
HYDRO TOOL – Halliburton’s Hydro tool, also known as
the fluid dielectric, capacitance, or watercut tool, is sensitive
to the dielectric constant of the flowstream. Wellbore fluids
flow through a tool chamber and affect the frequency of
an oscillator in the tool. Low frequencies correspond to
high-dielectric-constant fluids (water), and high frequencies
correspond to low-dielectric-constant fluids (hydrocarbons).
Consequently, the Hydro tool can distinguish between water
and hydrocarbons, but it may not be able to distinguish
between oil and gas because the frequency differences
Figure 15.3 (opposite page) — This TracerScan log was run to evaluate the effectiveness of hydraulic fracturing
operations. The fracturing program was designed to suitably limit the vertical extent of the propped fractures so that
zonal isolation could be maintained. The pad was tagged with scandium-46 and the proppant with iridium-192. On the
log, the gamma ray concentrations of both isotopes indicate that each of the three intervals remained isolated. The
scandium relative distance curve reveals that fractures in each zone extended beyond the perforated intervals, particularly
in the upper zone where the fractures propagated more than 50 ft above the perforations. However, the iridium relative
distance curve confirms that the propped intervals did not communicate with one another.
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FRACPAC COMPLETION SERVICES
Production Logging Toolstring
Gamma Ray
Flowmeter
Telemetry
Fluid
Density
Centralizer
Hydro
Collar Locator
Temperature
Pressure
Figure 15.4 — This production logging toolstring contains all the components necessary to evaluate threephase flow. The gamma ray and collar locator subassemblies provide information for accurate depth
correlation. The fluid density and Hydro devices furnish data for identifying the fluid components in the
flowstream, and the flowmeter measures the velocity of the flowing fluid mix. The pressure and temperature
tools supply particulars needed for PVT analysis.
between the two hydrocarbon phases are small. The tool
is calibrated so that water holdup can be calculated from
oscillator frequency.
FLUID DENSITY TOOL – The fluid density tool measures
the density of the flowstream. Wellbore fluid flows through
a tool chamber that has a gamma ray source at one end
and a gamma ray detector at the other end. The denser the
wellbore fluid, the fewer gamma rays reach the detector.
Thus, low detector count rates correspond to high fluid
density, and high detector count rates correspond to low
fluid density. The tool is calibrated so that fluid density
can be calculated from the detector count rate.
GRADIOMANOMETERS – Gradiomanometers also measure
fluid density. They contain an internal float system filled
with a special fluid. The pressure difference between two
points in the system is measured and used to determine a
pressure gradient, which in turn is converted to fluid
density. Gradiomanometer measurements must be corrected
for hole inclination, whereas measurements from fluid
density tools do not require such a correction.
162
Fluid Velocity
Spinner flowmeters, whether of the continuous, fullbore,
or diverter type, provide information related to the average
velocity of the fluid mix in the well. The wellbore fluid
velocity (both speed and direction) is calculated from the
spinner’s rotational speed and direction.
CONTINUOUS FLOWMETERS – Continuous flowmeters
contain a helical impeller, or spinner, with diameter slightly
less than that of the toolbody. These flowmeters are
designed for use in wells with moderate to high flow rates
and in wells containing tubing or small-diameter casing.
FULLBORE FLOWMETERS – Fullbore flowmeters contain
collapsible spinners that, after passing through tubing
into casing, open to a diameter larger than that of the
toolbody. These flowmeters are intended for use in wells
with low fluid velocities (common in larger casing sizes)
and in deviated wells where phase separation in the flow
stream may occur.
DIVERTER FLOWMETERS – Diverter flowmeters contain an
expandable metal basket that diverts wellbore flow through
the center of the tool where a spinner is located. These tools
are used in both inclined wells and in wells with low flow
rates. They are generally held stationary while making
their flow measurements.
Fluid Volume and State
As fluid flows through the wellbore, temperature and
pressure change, affecting the volume and state (liquid or
gas) of the fluid. Thus, the volume and state of a fluid
entering or leaving the wellbore downhole can be very
different from the volume and state of the same fluid at
the surface. The analysis of fluid volume and state changes
that occur with temperature and pressure changes is called
pressure-volume-temperature (PVT) analysis. Pressure and
temperature measurements are needed in PVT analysis
and are also useful in studying reservoir characteristics and
in locating zones that are producing or accepting fluids.
PRESSURE TOOLS – Both strain gauges and quartz transducers are used in production logging pressure tools. Strain
gauges respond more quickly to pressure changes, and thus
are used when real-time pressure measurements are needed.
On the other hand, quartz transducers have higher accuracy
and therefore can give superior data for analyzing pressure
drawdowns and buildups.
TEMPERATURE TOOLS – Temperature tools use a resistance
thermometer to measure wellbore temperature. A resistive
element that is part of an electrical circuit is exposed to
wellbore fluids; changes in fluid temperatures cause changes
in the element’s resistance. Fluid entering the wellbore, or
fluids leaving the wellbore and accumulating in the region
surrounding the wellbore, can alter the normal temperature
gradient in the well. The resulting temperature-gradient
anomalies can be used to identify producing zones, locate
zones that are accepting fluid, and detect channeling from
above or below.
Fluid Movement Behind Pipe
Several tools can give information about fluid movement
behind pipe. These include the Borehole Audio Tracer tool,
the Thermal Multigate Decay tool, the Pulsed Spectral
Gamma tool, and Radioactive Fluid Travel tools.
BOREHOLE AUDIO TRACER TOOL – The Borehole Audio
Tracer tool senses noise created by fluid movement in and
around the borehole. The tool is held stationary while
measurements are being made. This eliminates noise that
would occur as a result of tool motion. The logging system
records the maximum amplitude in each of four frequency
ranges extending from 200 Hz, 600 Hz, 1,000 Hz, and
2,000 Hz up to the maximum frequency to which the
tool is sensitive. On the log, amplitudes are plotted versus
depths, and individual points in each of the frequency
ranges are connected to produce the four noise curves.
The log is used to locate fluid flow, identify fluid type,
and give information about the type of passage through
which the fluids are flowing.
THERMAL MULTIGATE DECAY AND PULSED SPECTRAL
GAMMA TOOLS – A pulsed neutron source in the lower
part of Halliburton’s Thermal Multigate Decay and Pulsed
Spectral Gamma tools irradiates oxygen-rich fluids such as
water and CO2 to produce a radioactive isotope that quickly
decays and emits gamma rays. If the fluid is flowing upward
at a speed greater than the logging speed, the gamma rays
can be sensed by detectors in the upper part of the tool.
Thus, the tool can be used to detect upward fluid movement (both inside and outside casing), to determine vertical
fluid velocities, and to locate fluid entry and exit points
in the wellbore. Logging speed adjustments allow upward
fluid movement to be detected over a wide range of
borehole and annular cross-sectional areas.
RADIOACTIVE FLUID TRAVEL TOOL – The Radioactive
Fluid Travel tool determines fluid velocities by measuring
the time required for a tagged wellbore fluid to travel
between two gamma ray detectors. Wellbore fluids are
tagged with a small amount of radioactive fluid ejected
from the tool into the flowstream. This tool is useful in
wells with fluid velocities too low to use a spinner
flowmeter and in wells where it is desired to diagnose
vertical flow behind casing.
Analyzing Fluid Flow
The computer-assisted Production Log Analysis program
contains options that allow the analyst to combine production logging data with related wellbore and formation data.
Data Averaging
The PLA program can average production logging
measurements by depth or by zone. Zoning a well allows
spinner calibration plots to be used to establish spinner
threshold velocities, which in turn are necessary to calculate
average fluid velocity. It is advisable to average the fluid
density and Hydro logs from multiple passes to reduce
statistical variations that may be present in the data.
Stabilized flow is required when these passes are made.
Determining Average Velocity
The PLA program uses one of two methods to determine
average fluid velocity from cable speeds and spinner rates.
When multiple logging passes have been made over the
zone of interest, the Chi-square method is used. When
only a single pass has been made over the zone, a linear
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FRACPAC COMPLETION SERVICES
regression method is selected instead. Over discrete depth
intervals, the program automatically removes anomalous
spinner data that do not match the velocity profile. The
log displays quality indicators that show where such data
were removed.
Analysis Display
The PLA program produces an informative, easy-to-read
display of wellbore flow characteristics. The display shows
holdups and surface flow rates for each fluid phase at
standard pressure and temperature conditions. Downhole
flow rates can also be plotted, and the gas flow rate can be
subdivided into that attributable to gas coming out of
solution and that attributable to gas existing in the free
state. A wellbore sketch gives a clear picture of the
completion. It displays as many as four casing or tubing
strings, along with slotted liners, packers, sliding sleeves,
gravel packs, and perforations.
Figure 15.5 shows the data recorded during multiple
passes of a production logging string. Figure 15.6 shows
the result of applying the PLA program to that data.
Figure 15.5 (opposite page) — This production log was obtained by making eight passes in a flowing well. The wireline cable
speeds are shown in the second track from the right and indicate that four upward passes (dashed curves) and four downward
passes (solid curves) were made through the well. Spinner rotational speeds for the passes are displayed in the rightmost track
and clearly indicate the entry of fluid into the wellbore over the three perforated intervals shown in the wellbore sketch. The
temperature and pressure curves plotted to the left of the sketch reflect an almost linear variation of the two parameters with
respect to depth. The fluid density curve presented to the right of the sketch indicates a change in wellbore fluid density at the
bottom part of the lowermost set of perforations.
164
Production Log
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FRACPAC COMPLETION SERVICES
Production Log Analysis
Figure 15.6 — The production logging data of Figure 5 were analyzed with the PLA program to obtain these
results. The holdup curve in the leftmost track indicates that there was two-phase production. In the three
tracks to the right of the wellbore sketch are three production presentations: (left to right) cumulative
production as a continuous function of depth, cumulative production averaged over each of the three
perforated intervals, and individual production from each of the three intervals. Note that all three intervals
produced oil at about the same rate, but the upper interval produced much less water than the lower two.
166
Chapter 16
INTRODUCTION
The case histories in this chapter are
included to illustrate the entire process
of FracPac Completion Services. Where
pretreatment production data were
available, they are used to contrast the
results after a FracPac treatment. Cases
from both the Gulf of Mexico and West
Africa are included to show the versatility of FracPac Completion Services
in all types of poorly consolidated,
high-permeability reservoirs.
CASE HISTORY NO. 1
LOCATION – This offshore-Louisiana
well was completed at 6,000 ft in a
relatively low-permeability (10- to 50md) pay zone with approximately 100
ft of gross pay.
PROCEDURES – After perforating at
12-spf in underbalanced conditions, the
pay zone was acidized with 1,000 gal of
hydrochloric acid containing an ironcontrol additive. A step-rate test and
minifrac test were performed using
80-lb/Mgal linear HEC gel. Fluid
efficiency was determined to be
approximately 45% with fractureclosure pressure of 4,000 psi. A
screenout design was planned on a
pseudo-3D fracture simulator.
The following pumping schedule (see
Table 16.1) was followed during the
treatment. A 5,000-psi increase in
bottomhole pressure indicated that
screenout had occurred, and that
proppant was packed to the wellbore.
The total volume of 20/40 synthetic
proppant placed was approximately
33,000 lb (See Figure 16.1).
Case
Histories
RESULTS – Since this well was originally
gravel packed, the results from a postcleanup-buildup test were startling.
A negative skin factor was achieved,
which was very unusual for a gravelpacked well in this area. The negative
skin factor indicates that the nearwellbore damage from the original
gravel pack was bypassed and that a
relatively low-permeability formation
benefitted from the stimulation.
CASE HISTORY NO. 2
LOCATION – This offshore-Louisiana
well was completed at about 10,000 ft in
a high-permeability formation (500 to
1,000 md). The pay zone grossed
approximately 50 ft.
PROCEDURES – After the well was
perforated in underbalanced conditions
at a 12-spf, a step-rate and a minifrac
test were performed to gather input
data for a propped fracture design.
Refer to Figure 16.2 for a log of the
FracPac treatment performed. Fractureclosure pressure was determined and a
net-pressure match was obtained using
a pseudo-3D design simulator. A fluid
efficiency of 10% was calculated, and
the treatment schedule that follows (see
Table 16.2) was designed accordingly.
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FRACPAC COMPLETION SERVICES
Table 16.1 — Case History No. 1 Pumping Schedule
Clean Volume
Proppant Concentration
Cumulative Proppant
Stage
Event
(gal)
(lb/gal)
(lb)
1
Pad
500
0
n/a
2
Proppant
1,000
2
2,000
3
Proppant
2,500
2 to 12 ramp
19,500
4
Proppant
1,150
12
+ 33,000
5
Flush
n/a
n/a
n/a
Case History No. 1
15
16
18
19
20
9
18
8
16
Slurry Rate
7
psi (1,000)
17
14
6
12
5
10
4
8
3
6
PConc/Slurry
Annulus
Pressure
2
4
Tubing
Pressure
1
2
0
0
4
8
12
16
20
Time (min)
24
28
32
36
Figure 16.1 — A new completion, offshore from Louisiana, was perforated at 12 spf in
underbalanced conditions. The pay zone was first acidized, then a step-rate test and minifrac
test were performed. An 80-lb/Mgal linear HEC gel was used to place 33,000 lb of proppant. A
negative skin factor was achieved, which was highly unusual in this unconsolidated formation.
168
bbl/min (slurry rate)
lb/gal (proppant concentration)
13 14
10
Table 16.2 — Case History No. 2 Pumping Schedule
Clean Volume
Proppant Concentration
Cumulative Proppant
Stage
Event
(gal)
(lb/gal)
(lb)
1
Pad
15,000
0
n/a
2
Proppant
7,000
0.5 to 4.0 ramp
16,000
3
Proppant
3,500
4.0 to 12.0 ramp
36,000
4
Proppant
1,000
12
48,000
5
Flush
n/a
n/a
n/a
Case History No. 2
6
250
BHP (Gauge)
Slurry Rate
psi (1,000)
4
3
200
BHT (Gauge)
Tubing Pressure
150
2
100
PConc/Slurry
PConc/Bottom
1
bbl/min (slurry rate)
lb/gal (proppant concentration)
5
300
50
0
0
10
20
30
Time (min)
40
50
Figure 16.2 — Another offshore-Louisiana well in a high-permeability formation was treated
with FracPac. The well was perforated at 12 spf, and a step-rate and minifrac test were
performed. A 40-lb/Mgal borate-crosslinked HPG was pumped according to a staged schedule.
Response from the well was a production rate of 10 MMcf/D with very low drawdown, results
typically unheard of from wells in this area.
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FRACPAC COMPLETION SERVICES
Step Rate Test
7,000
ellhead Pressure (psi)
5,000
Rate
(0 to 20 bbl/min)
18:37:06
Fracture Extension @ 1.1 bbl/min, 5,930 psi Wellhead Pressure
Roughly 9,360 psi Bottomhole Pressure (Excluding Friction)
4,000
0
1
2
3
4 5 6 7
Rate (bbl/min)
18:29:06
8
9
Tubing
Pressure
10 11
18:45:06
Figure 16.3 — Fracture-extension pressure is determined from a
step-rate test. This test used 70 bbl of water that was pumped at
0.3 to 8.0 bbl/min after formation breakdown occurred.
Proppant
Concentration
(0 to 10 lb/gal)
S2
S3
18:53:06
(0 to 15,000 psi)
19:01:06
S4
Pressure vs.
Square Root of Shut-In Time Plot
19:09:06
S5
5,400
Wellhead Pressure (psi)
Time (h:m:s)
6,000
W
Bottom Hole
Pressure Calculated
(0 to 15,000 psi)
S6
S7
19:17:06
5,200
19:25:06
5,000
19:33:06
4,800
4,600
4,500
0
10
20
30
Shut-In Time (min)
40 50 60
Figure 16.4 — Fracture closure pressure and closure time are
determined from a minifrac test. Relatively small fluid volumes,
as compared with the main fracturing treatment, are pumped.
Fluid efficiency in this test was calculated at 25% to 35%.
170
Figure 16.5 — The pressure log from the main treatment
tells both operators and clients how the formation is
responding to the treatment, and whether the treatment
matches the design. The fracture design for this well was
developed from minifrac data. A designed stage of
36,000 lb of intermediate-strength, 20/40 proppant was
pumped. The well screened out at 33,000 lb.
This well happened to have existing bottomhole gauge
information available, and a gravel-pack packer and screen
assembly were already installed. The treating fluid used
was a 40-lb borate-crosslinked HPG, and a 20/40
synthetic proppant was used. Pumping rates for the job
were 25 bbl/min.
RESULTS – The well responded with a 10-MMcf/D
production rate with very low drawdown, which was very
unusual for wells of this area.
CASE HISTORY NO. 3
LOCATION – This offshore -Texas gas well was deviated and
completed at 12,000 ft (10, 300 TVD). The formation was
a 10-md sandstone with a gross pay zone height of 80 ft.
WELL DESCRIPTION AND PROCEDURES – From the bottom
of the well at 12,100 ft MD (10,000 ft TVD) to 10,500
ft MD (9,400 ft TVD), 5-1/2-inch liner was in place.
Intermediate casing was in place from 10, 500 ft MD to
the surface. A tapered workstring was deployed using
3-1/2-inch tubing from the surface to 7,200 ft MD and
2-7/8-inch from 7,200 ft to 10,450 ft, where the sealbore
packer was set. Because of the limited amount of seal area
on the casing wall, there was concern about how much the
tubing string might contract during the treatment. All
treating fluids were heated to minimize the temperature
differential and the contracting effect it has on the
tubing string.
A step-rate test was performed. The step-rate test used
70 bbl of treated water, which was pumped at rates from
0.3 to 8.0 bbl/min after breakdown occurred. Fractureextension pressure was determined from this test as is
shown in Figure 16.3.
A 150-bbl minifrac test was also performed. A 40-lb/Mgal
borate-crosslinked HPG fluid was pumped at 10 bbl/min.
Fracture-closure pressure and closure time were determined
from the minifrac test and are shown in Figure 16.4. Fluid
efficiency was calculated at 25% to 35%.
The propped-fracture design was developed from the data
acquired in the minifrac test. A pad volume of 300 bbl of
40-lb/Mgal borate-crosslinked gel was pumped at 10 bbl/
min. The pad was followed by a proppant stage of 36,000
lb of intermediate strength, 20/40 synthetic proppant.
Screenout occurred after 33,000 lb of proppant were placed
in the formation, as shown in Figure 16.5.
2 MMcf/D. A postjob-buildup test showed the well to
have less than a 5 skin, with production rates of
10 MMcf/D.
CASE HISTORY NO. 4
LOCATION – A major producer in West Africa wanted the
benefits of fracture stimulation and the protection of sandcontrol techniques combined to reduce skin and maximize
production from 7 new wells in a field to be developed.
Sand control and high production rates were of primary
importance to the operator, since these wells promised
excellent production potential.
Previously, hydraulic fracturing was considered unnecessary in such high-permeability formations. However, when
the operator realized the long-term benefit in production
that FracPac offers by incorporating fracturing and sand
control, they were eager to apply this technique.
WELL DESCRIPTION AND PROCEDURES – In the first well
of the series, two producing intervals were completed. A
linear HEC gel and 20/40 synthetic proppant were
pumped into both of the intervals. Both fracture treatments
were performed and a gravel pack was placed over the
entire interval. Production results were good, with a skin
factor measured below 2.0. The successful results in this
first well prompted the decision to use FracPac techniques
to complete the remaining wells in the project.
In the second well treated, borate-crosslinked fluid was
used. This type of fluid performed much better in the
high-permeability zones by controlling fluid loss. The
discovery of less fluid loss with borate-crosslinked fluids
led to dual-fluid systems being pumped where highpermeability zones were encountered in other wells. In
such wells with high-permeability zones, a boratecrosslinked HPG was pumped as a pad volume to initiate
the fracture. The proppant stage of the treatment was then
placed with linear HEC gel, to ensure maximum fracture
conductivity. This dual-fluid technique was most effective
in placing large volumes of proppant into the wells.
RESULTS – The proppant-packed fractures in these WestAfrican wells have proven very effective in reducing skin
and increasing production, while providing excellent
sand control.
RESULTS – A prejob pressure buildup test determined that
the well had a 30+ skin and was producing approximately
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FRACPAC COMPLETION SERVICES
172