Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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125
FRACTURING
FLUIDS
AND ADDITIVES
The fracturing fluids used in early treatments consisted
of
crude and refined oils,
because
of
possible detrimental aspects of contacting a hydrocarbon reservoir with
water (Burnham et al., 1980). Subsequent experience with the appropriate additives
(e.g., clay control materials and surfactants) showed that most reservoirs can be
treated using an aqueous fluid.
The fracturing fluid (1) opens and extends a fracture hydraulically, and
(2)
transports and distributes the proppant along the fracture. The properties
of
this
fluid are of utmost importance. There is a low efficiency in hydraulic wedging and
extending of the fracture in the case
of
rapid leakoff
of
fracturing fluids into the
surrounding formation (Veatch, 1983a). Fluid leakoff may damage the formation,
reducing the wellbore matrix permeability by blocking the pore channels. Internal
fracturing pressure and the proppant agent transporting characteristics can be
controlled by adjustment of the fracture fluid viscosity. Inasmuch as the fluid may
react with the formation and/or the proppant within the fracture itself, proper
selection
of
the fracturing fluid is critical. Obviously, the cost
of
the fluid is also
of
great importance. Temperature and pressure at which the treatment takes place,
which may determine the ability
of
a particular type of fluid to perform, must also
be considered in the final selection
of
the fluid.
Veatch (198313) listed the following requirements in the selection
of
a fracturing
fluid: (1) low fluid loss to achieve designed penetration with minimum fluid
volumes,
(2)
sufficient effective viscosity to create the necessary fracture width and
to transport and distribute the proppant in the fracture as required,
(3)
no excessive
fraction in the fricture,
(4)
good temperature stability at reservoir temperatures,
(5)
good fluid shear stability,
(6)
minimal damaging effects to the formation matrix
permeability,
(7)
minimal plugging effects on fracture conductivity,
(8)
low friction
loss in the pipe, (9) good post-treatment breaking characteristics, (10) good
post-treatment cleanup and flowback behavior, and (11) low cost.
The fracturing fluid lost to the formation opposite the fracture face decreases the
relative permeability to the oil and/or gas and, thus, decreases the formation
post-treatment deliverability. Fracture fluid invasion may also cause the reduction
of
matrix permeability as a result of the swelling of clays in the formation. The
degree
of
damage is dependent upon the initial permeability, content and type
of
formation clay, and type
of
fracturing fluid.
Liquid and solid residues are left behind in the fracture by the fracturing fluid. If
the fracture face is softened by the fluid, proppant embedment will result in the
reduction of fracture-surface permeability. The effect
of
effective stress on fracture
conductivity already shows the degree
of
damage.
A
gentle slope
of
the curve in
Figs.
4-27
and
4-28
indicates the packing of the proppants with increasing stress.
For the three samples shown, points
B,
C,
and
D
represent the stabilized fracture
conductivity with no fracturing fluid damage, whereas points
B',
C',
and
D’
represent the lowest fracture conductivity equal to or greater than that
of
packed
fractures at the same applied stresses. The following factors reduce fracture conduc-
126
m
E
>
k
?
n
2
102-
z
0
w
E
3
+
V
4
rY
LL
EFFECTIVE
STRESS,
psi
Fig.
4-27. Fracture conductivity versus effective stress
for
a Devonian shale, Martin County, Kentucky.
(After Republic Geothermal, Inc., 1980, fig.
1,
p. 1-7; courtesy
of
the
U.S.
Department
of
Energy.)
Depth
=
3028
ft, test temperature
=
24O
C
(75
OF),
proppant
=
20-40 mesh sand, proppant distribution
=
packed layer,
0.3
Ib/ft2.
EFFECTIVE
STRESS,
MPe
5
10
15
20
in3L
I
I
I
I
VIRGIN
SAMPLE
I
LAYER
lOlo
L
I000
moo
3000
EFFECTIVE
STRESS,
psi
Fig.
4-28. Fracture conductivity versus effective stress for Medina sandstone in New York. (After
Republic Geothermal, Inc., 1980, fig.
1,
p.
1-7;
courtesy of the
US.
Department
of
Energy.) Depth
=
4022
ft,
test temperature
=
24O
C
(75
OF), proppant
=
20-40 mesh sand, proppant distribution
=
packed layer,
0.3
lb/ft2.
127
TABLE
4-1
Scaling factors for productivity estimates (see Fig.
4-10)
(After McGuire and Sikora,
1960;
courtesy of
the Society
of
Petroleum Engineers)
Well Drainage
(wk,/k)
(J/JO
1
(acres) (ft)
spacing radii
20 467
1.42 1.05
40 660
1
.00 1.00
80
933
0.71 0.95
160
1320
0.50 0.91
320 1867
0.35
0.87
640
2640
0.25 0.84
For
other spacing
(A)
and radii:
wk,/k
=
J4o/A
3.095
J/Jo
=
log(0.472)(
re/rw)
tivity (Republic Geothermal, Inc.,
1979):
(1)
packing
of
a proppant which is
predominant in fully-packed layers,
(2)
proppant embedment due to softening of
fracture face,
(3)
proppant crushing which is predominant in a partial layer,
(4)
TABLE
4-11
Commonly used fracturing fluid systems (After Veatch,
1983b,
table
I,
p.
854;
courtesy
of
the Society
of
Petroleum Engineers)
Water-base polymer solutions
of
Natural guar gum (guar)
a
Hydroxypropyl guar (HPG)
a
Hydroxyethyl cellulose (HEC)
Carboxymethyl hydroxyethyl cellulose (CMHEC)
a
Polymer water-in-oil emulsions
2/3
hydrocarbon
+
1/3
water-base polymer solution
Gelled hydrocarbons
Petroleum distillate, diesel, kerosene, crude oil
Gelled alcohol (methanol)
Gelled CO,
Gelled acid (HCl)
Aqueous foams
Water phase: guar, HPG solutions
Gas phase: nitrogen, CO,
a
Can be crosslinked to increase viscosity.
Petroleum distillate, diesel, kerosene, crude oil.
Usually guar or HPG.
128
fracture fluid residue clogging of channels in packed layers, (5) clogging of channels
due to release of fines, and (6) clay flocculation especially at proppant embedment
locations.
The various types
of
fluid systems used for fracturing treatment are listed in
Table 4-11. Additives are added to the fluid (see Table 4-111) for controlling its
properties. According to Veatch (1983b), the selection of the type of fracturing fluid
should be based upon the following variables:
(1)
formation temperature, (2) fluid
temperature profile, (3) the length of time the fluid will remain in the fracture, (4)
proposed treatment volume and pumping rates, (5) type of lithology (sandstone,
dolomite, limestone, etc.), (6) fluid loss, (7) formation sensitivity to fluids,
(8)
clay
content and type, (9) reservoir pressure,
(10)
pumping pressure, (11) pipe-friction
losses,
(12)
type(s) and quantity of proppant, and
(13)
fluid breaking requirements.
Oil-base
fluids
Gasoline, kerosene, diesel oil, or crude oil thickened by napalm (an aluminum
fatty acid salt), an alkali metal, or aluminum carboxylate were the first fluids used
in hydraulic fracturing operations (Minich, 1945). The gelling increased the viscosity
of the fluid and helped reduce the fluid loss while injecting the material into the
formation. Later, when the gel broke, the viscosity was reduced and fluid flowed
freely back into the wellbore. This also improved the ability of the oil-base fluid to
carry proppants. The use of carboxylate salts resulted in improved fluids using
aluminum orthophosphates (Pellegrini and Strange, 1961; and Crawford et al.,
1973). The gelled oil was often followed by a viscous refined oil, such as API
No.
5
and
No.
6 residual fuel oil, lease crude oil, fatty acid-soap gels, and, finally, by
emulsions and acid-base fluids (Howard and Fast, 1970, p.51).
Fluid-loss-control additives should (see Howard and Fast, 1970,
p.51):
(1)
be
required in small concentrations, (2) be easily produced back from the formation
upon completion of the treatment,
(3)
be relatively inert and/or compatible with the
formation fluids, and (4) not cause emulsions that might hamper surface treatment
and shipping of the produced crude oil. Alkaline earth salt of a sulfonated
alkylbenzene was found to help reduce the. fluid loss of lease crude oil systems,
refined oils, and emulsions (Brown and Landers, 1957; Phansalkar et al., 1962).
Gilsonite, asphalts and blown asphalt have also been used to reduce the fluid loss
(Steward and Coulter, 1959).
Friction reducing additives often used in oil-base fracture fluids are
(1)
fatty acid
soap-oil gel, and (2) high-molecular-weight hydrocarbon polymer. The fatty acid
soap-oil, while reducing the friction of the system, also tends to increase the fracture
fluid viscosity. Aluminum orthophosphate fluids enhance temperature stability and
frictional drag reduction (Burnham et al., 1980). This additive can control the
viscosity of the fracture fluid at temperatures of up to 225
OF
(107
O
C).
At higher
temperatures, the gelled hydrocarbons are presently inferior to aqueous fluids in
their ability to handle propping agents. The biggest problem seems to be the lack of
thixotropic properties.
129
Temperature
("C)
10
30
50
70
90
110
121.1
10,000
2
30
6ol
OL
50
i4
Aluminum Phosphate
,>
100
150
200 250--Time
(hrs)
at 250°F
--
1
9,000
5.000
4.000
2
3,000
&
2,000
1,000
I
Temperature
(OF)
0
05
10
15
2
0
Fig.
4-29. Viscosity profile comparison for kerosene containing an aluminum phosphate thickener with
and without delayed aluminum phosphate. (After Burnham et al., 1980, fig.
2,
p. 218; courtesy
of
the
Society of Petroleum Engineers.)
Baker et al. (1970) proposed the formation of association colloids after proper
dispersion of alkali metal or aluminum carboxylates in nonpolar media. Burnham et
al.
(1980) described several successful fracture treatments using a "delayed"
aluminum phosphate as the gelling agent with
HST's
of
190-285
OF
(88-141" C).
The delayed gelling agent dissolves completely in the fluid at
150OF
(66"C),
resulting in
high
viscosities in the fracture with only moderate viscosities at the
surface (Fig. 4-29).
The oil-base fracturing fluids are particularly useful where the formation is (1)
water sensitive, due to a significant clay content in the reservoir matrix that will
swell when contacted by waters containing different concentrations and/or types of
ions, or (2) water soluble. Serious problems may arise, however, if the oil-base
fracturing fluid forms emulsions in the reservoir rock pores. This will reduce the
matrix permeability to fluid flow. Oils could be re-used when produced back from
the formation.
Water-base
fluids
Water is the most commonly used fracturing fluid due to its low cost and
availability. The gelling agents used in most aqueous fracturing fluids are polymeric
hydrophilic chemicals. The most common classes
of
polymers used in fracturing
fluids are gum guar (Fig. 4-30), gum guar derivatives (Fig. 4-31), cellulose deriva-
tives (Fig. 4-32), polyacrylamides (Fig. 4-33), and partially hydrolized polyacryl-
amides (Root, 1966). Water-base system can be economically designed through the
addition
of
additives to handle a wide range
of
formation types, depths, pressures,
and temperatures. In the earlier days of fracture treatment, water-base fluids were
thought to be harmful for oil formations and were not commonly used. In 1965,
130
REPEATING UNIT
FOR
GUAR POLYMER
n
=
400-630
r
1
Fig.
4-30. Repeating unit for guar gum.
n
=
400-600. (Courtesy
of
the Halliburton Co., 1976, fig. 12.1, p.
46.)
REPEATING UNIT
FOR
GUAR DERIVATIVE
R=H
OR
HYDROXYALKYL GROUP
n
-
400-600
1
Fig.
4-31. Repeating unit for guar derivative R=H or hydroxyalkyl group.
n
=
400-600. (Courtesy of the
Halliburton Co., 1976, fig.
12.2,
p. 47.)
REPEATING UNIT
FOR
CELLULOSE
DERIVATIVE R=H,
HYDROXYALKYL,
OR
CARBOXYMETHYL
n
-
3-4M
Fig.
4-32. Repeating unit for cellulose derivative R=H, hydroxyalkyl, or carboxymethyl.
n
=
3-4M.
(Courtesy of the Halliburton Co., 1976, fig.
12.3,
p. 47.)
131
Fig. 4-33. Repeating unit
for
polyacrylamide
R=NH,
or
0-
Na+.
n
=15-250M. (Courtesy
of
the
Halliburton Co., 1976, fig. 12.4,
p.
47.)
Black and Hower (1965) noted that two-thirds of the wells were being fractured with
water-base fracturing fluids. Today the percentage is probably around
80%.
The
advantages of water-base fracturing fluids over other systems include: (1) reduced
fire hazard during treatment, (2) availability of water in large quantities in most
areas,
(3)
generally low cost
of
obtaining water when compared to other fluids,
(4)
ease of mixing additives in a water-base system compared to that €or other types of
fluids,
(5)
generally lower viscosities for water-base systems which result in lower
pumping pressures, and (6) higher specific weight of water as compared
to
that of
oil or other fluids, which yields a higher hydraulic head on the formation to be
fractured. This reduces the actual cost of the operation because of lower pump
pressures (or lower horsepower) required to produce the desired downhole pressures.
Operators often experience a 20-30% drop in cost after switching from oil-base to
water-base systems. In addition, it is easy to chemically modify the properties of
water.
Ousterhout and Hall (1961) described the action
of
friction-reducing agents on
water-base systems as a suppression of fluid turbulence. The presence of a small
amount of high-molecular-weight linear polymer (Fig. 4-32), such as polyacryl-
amide, reduces the swirling and eddying when the fluid is in motion and thus
reduces the turbulence
of
the fluid. Consequently, the friction-reducing material
extends the range of laminar flow to higher velocities.
“Surfactants” (surface-active agents) are commonly-used additives in water-base
systems. They reduce the interfacial tension and resistance
to
the fluid flow back
from the formation, after treatment. Obviously, the initial type of wettability
(oil-wet, water-wet, or mixed) of the formation must be known.
In
addition, control
of interfacial tensions can help reduce (or limit) generation of foam in the presence
of gas. Bernard et al.
(1965)
pointed out that generation of foam in the pore and
flow channels can reduce the flow capacity
of
the fluid, which reduces the effective-
ness of the treatment. In the case of gas well stimulation, McLeod and Coulter
(1966) pointed out that addition of 10-20% alcohol results in reduction
of
the
interfacial tensions and improvement of the fracturing fluid penetration into the
reservoir. Economic considerations (i.e., high cost of alcohol), however, limits this
application.
132
::m
300
0
:
200
’
100
-
0
I
2
TIME,
hr
Fig.
4-34.
Relationship between viscosity and time of a crosslinked fluid at
250
OF.
Initial viscosity is at
room temperature. (After Horton, 1982, fig. 1, p.
76;
courtesy of
Drilling.)
Gum guar is one of the more widely used additives for salt- and fresh-water
systems. The gum will hydrate readily and thicken the fluid, increasing the viscosity
and decreasing the fluid loss of the fluid. Gum guar can be dissolved in a slightly
alkaline solution without increasing its viscosity on addition of borax. In general,
the lower the pH, the thicker the gel and the hgher the viscosity of the fluid. Gum
guar and hydroxypropyl guar (HPG) can be crosslinked for greater viscosity and a
higher temperature tolerance (Veatch, 1983b). Temperature stability has been in-
creased by the addition of oxygen scavengers (e.g., thiosulfate salts and methanol).
Fracture fluids that are stable under high temperatures are required in fracture
treatment
of
deeper wells. The temperature in deeper wells ranges from 300 to
350
OF
and most fracture fluids are only marginally stable under these conditions
(Horton, 1982, p.
75).
Much research is currently being conducted on fluids up to
700°F
to stimulate geothermal wells. The two fluid systems utilized today are the
“crosslinked” and the “gelled two-stage”. The crosslinked fracture fluid is generated
by use of a polymer.
A
crosslinked system does not pour readily and has a near
gello-like consistency, which is caused by the chemical reaction of certain polymer
chains-they become interconnected and thcken the fluid (Horton, 1982, p.75). The
high viscosity enables the fluid to carry heavy loads of proppant. Upon encounter-
ing hgh temperatures, the chemical bonding of the crosslinked system is destroyed
by
heat, as shown in Fig. 4-34.
;
;;:py-j
0
1
%
50
00
I
2
TIME,
hr
Fig.
4-35.
Relationship between viscosity and time (two-stage reaction) at
300
F,
as the fluid is being
pumped downhole. Initial viscosity is at room temperature. (After Horton, 1982, fig. 2,
p.
76; courtesy
of
Drilling.)
133
The two-stage system, also referred to as “polymer loading”, is more resilient and
less sensitive to temperatures. It is prepared initially as a gel at the surface.
Dry
polymer (secondary “inhibited” gelling agent) is then added to the fluid as it is
being pumped downhole. This secondary gelling agent does not generate additional
viscosity under ambient or surface conditions. Upon being heated to a temperature
of around 300 OF, however, the polymer reacts chemically and increases the viscos-
ity of the fluid. Figure 4-35 shows variation
of
viscosity with time for a two-stage
fluid.
Acid-base fluids
Acid-base fluids have similar properties to those of water-base systems. Im-
portant factors which are considered in designing a fracture treatment are viscosity,
friction loss, and fluid loss. Acid-base fluids require control
of
the pH (concentra-
tion of acid) and how the acid reaction might be modified by the presence of
additives which are used to modify the properties
of
fracturing fluid. As with
water-base systems, gum guar is often used to control friction
of
fluid, viscosity, and
fluid loss. Gum guar is not stable in concentrations
of
hydrochloric acid above 15%.
In general, it is only effective at low temperatures. Polyacrylamides rather than gum
guar are used to control these properties at hgher temperatures.
Howard and Fast (1970, p.
54)
pointed out that fluid-loss control is difficult
because of the action of the acid on the formation and on the fluid-loss-control
agent. Two types of agents are often used to control the fluid loss: (1) synthetic
polymers that remain stable and swell in acid, and
(2)
blends of acid-resistant gums,
silica flour. and oil-soluble resins.
Gelled acids
A gel or thickened acid is generally prepared by using natural gums such as gum
guar or gum karaya. Synthetic polymers and cellulose derivatives are more expen-
sive and
so
are considered economically noncompetitive (Howard and Fast, 1970, p.
54). The gelled acid fills the main fractures and, thus, results in a deeper penetra-
tion. The
high
cost and lack of stability at temperatures above 100
O
C
have resulted
in the loss of popularity.
Acid emulsions
Acid-in-oil emulsions with a 60-90% aqueous, internal acid phase are often used
in wells with high temperatures because
of
their stability (Howard and Fast, 1970, p.
54).
The emulsifier selected is typically a mixture of nitrogen-based organic com-
pounds and non-ionic surfactant-type materials. The system is designed
so
that the
emulsifier makes the emulsion stable at surface conditions. When the emulsion is
heated to formation temperatures, however, the emulsion breaks down. At high
temperatures, the emulsifier is either adsorbed on the rocks and/or is broken down.
Popularity of acid emulsion treatments is due to the fact that they can be used in
134
high-temperature wells and slow reaction rate which results in a deeper fracture
penetration. The primary disadvantages of acid emulsions are high viscosities and
high friction losses.
Chemically retarded acids
Knox et al. (1964) pointed out several advantages of chemically retarded acid as
a fracturing fluid. They discussed the addition of surfactants to retard the acid
reaction on carbonate rocks (limestones and dolomites). According to Knox et al.
(1964), the most effective surfactants for this are the anionics such as alkyl
phosphate, alkyl sulfonate and alkyl taurate. These materials make the surface of
the water-wet carbonate rock oil-wet, preventing the water phase (containing the
acid) to contact the surface of the rock. The problem arises, however, if the
carbonate rock in situ is originally oil-wet. In such cases surfactants may not be
necessary. Howard and Fast (1970) pointed out that alkyl sulfonate is the most
economic material for use in retarding acids. This retardation permits the acid to be
transported further from the wellbore before it reacts with the rocks, thus increasing
the depth
of
live acid penetration.
Aqueous foams
Aqueous foams usually exhibit excellent “postfracture cleanup” characteristics
when used in stimulating abnormally low-pressured reservoirs or those reservoirs
that present postfracture cleanup problems.
Typically, the fluid consists
of
20%
water and
80%
gaseous nitrogen. The relative
proportions of these components can be varied depending upon the viscosity
required of the foam. Surfactant in the amount of
0.5-1.0%
is added to stabilize the
foam. The viscosity is a function of content by volume
of
nitrogen. For example, if
80%
of the foam consists of nitrogen, the fluid is called an 0.80-quality foam.
lnasmuch as the foam is compressible, the quality
on
the surface
is
different from
that in the fracture at the bottom
of
the well at hgh pressures. Consequently, use of
foam systems is generally limited to low-pressure reservoirs (Veatch, 1983b).
The advantages of the foam are
(1)
hgh
viscosity,
(2)
very good proppant
suspending and carrying capabilities, and (3) a very low fluid
loss.
Consequently,
the foams have greatest application in fracturing of gas wells where fluid retention
can be a problem in regaining permeability to gas after treatment. The small content
of
water in foams is a disadvantage at low injection rates as it is difficult for this
water to carry proppants prior to the making of the foam.
PROPPING AGENTS
FOR
HYDRAULIC FRACTURING
The fracturing fluid cracks or fractures the formation and then holds it open until
the pressure is reduced. The two walls or faces of the fracture will close or “heal” as