Note: Descriptions are shown in the official language in which they were submitted.
lz4~
METHOD FOR PLACING BALL SEALERS
_TO CASING PERFORATIONS IN A DEVIATED WELLBORE
s
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention pertains to the treating of wells and,
more particularly, to a method for selectively restricting the
flow of fluids through perforations in a deviated oil well
casing by small balls or spheres of appropriate size.
~. Description of the Prior Art
It is common practice in drilling oil and gas wells to
deviate the wellbore from the vertical. When the wellbore is
intentionally deviated from the vertical, it is called
directional drilling. Directional drilling has application in
several situations such as producing from inaccessible locations
(i.e. populated areas, hostile environments, under rivers,
etc.), drilling from offshore platforms, and sidetracking a
vertical wellbore after the original well was drilled into
water-bearing formations or after downhole problems require
abandonment of the lower portion of the wellbore.
It is common practice in completing oil and gas wells,
including deviated wells, to set a string of pipe, known as
~.~4~?615
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casing, in the well and to pump cement around the outside of the
casing to isolate the various formations penetrated by the
well. To establish fluid communication between the
hydrocarbon-bearing formations and the interior of the casing,
the casing and cement sheath are perforated.
At various times during the life of the well, it may be
desirable to increase the production rate of hydrocarbons by
acid treatment or hydraulic fracturing. If only a short,
single, hydrocarbon-bearing zone in the well has been
perforated, the treating fluid will flow into this productive
zone. As the length of the perforatéd zone or the number of
perforated zones increases, treatment of the entire productive
zone or zones becomes more difficult. For instance, the strata
having the highest permeability will most likely consume the
major portion of a given stimulation treatment leaving the least
permeable strata virtually untreated. Therefore, techniques
have been developed to divert the treating fluid from the high
permeability or undamaged zones to the low permeability or~
damaged zones.
Various mechanical techniques for selectively treating
multiple zones have been suggested including techniques using,
for example, packers, baffles and balls, bridge plugs, and ball
sealers.
Packers have been used extensively for separating zones
for treatment. Although these devices are effective, they are
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expensive to use because of the associated workover equipment
required for the tubing-packer manipulations. Moreover,
mechanical reliability tends to decrease as the depth or
deviation of the well increases.
In using baffles and balls to separate zones, a baffle
ring, which has a slightly smaller inside diameter than the
casing, fits between two joints of casing so that a large ball,
or bomb, dropped in the casing will seat in the baffle. After
the ball is seated in the baffle, the ball prevents further
fluid flow down the hole. One disadvantage of this method is
that the baffles must be run with the casing string. ~oreover,
if two or more baffles are used, the inside diameter of the
bottom baffle may be so small that a standard perforating gun
cannot be used to perforate below the bottom baffle.
A bridge plug, which is comprised principally of slips,
a plug mandrel, and a rubber sealing element, has been run and
set in casing to isolate a lower zone while treating an upper
section. After fracturing or acidizing the well, the plug is
generally retrieved, drilled, or knocked to the well bottom with
a chisel bailer or drillpipe. One difficulty with the bridge
plug method is that the plug sometimes does not withstand high
differential pressures. Another problem with this technique is
that the placement and removal of the plug can be expensive due
to rig costs and associated equipment.
lZ4q~6~5
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One of the more popular and widely used diverting
techniques uses ball sealers. In a typical method, ball sealers
are pumped into the well along with the formation treating
fluid. The balls are carried down the wellbore and to the
perforations by the fluid flow through the perforations. The
balls seat upon the perforations and are held there by the
pressure differential across the perforations.
Although ball sealer diverting techniques have met with
considerable usage, the balls often do not perform effectively
because only a fraction of the balls injected actually seat on
perforations. Ball sealers having a density greater than the
treating fluid will often yield a low and unpredictable seating
efficiency, highly dependent on the difference in density
between the ball sealers and the fluid, the fluid viscosity, the
flow rate of the fluid through the perforations, and the number,
spacing and orientation of the perforations. The net result is
that the plugging of the desired number of perforations at the
proper time during the treatment to effect the desired diversion
is left virtually to chance.
Lightweight ball sealers are ball sealers having a
density less than the treating fluid density and have been
successfully used to improve seating efficiency. The treating
fluid containing lightweight ball sealers is injected down the
well at a rate such that the downward velocity of the fluid is
sufficient to impart a downward drag force on the ball sealers
greater in magnitude than the upward buoyancy force of the ball
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sealers. Once the ball sealers have reached the perforations,
all will seat and plug the perforations provided fewer balls are
injected than there are perforations accepting fluid, thereby
forcing the treating fluid to be diverted to the remaining open
perforations. Although these lightweight ball sealers can be
highly effective in improving diversion, one problem with using
these ball sealers occurs when the downward flow of fluid in the
casing is so slow that the drag forces exerted on the balls by
the treating fluid may not overcome the upward buoyancy force of
the ball sealers and thus the ball sealers may not be
transported to the perforations. This problem is generally
experienced during treatments pumped at low rates and in
particular matrix treatments such as matrix acidizing.
One prior method of selective diversion is disclosed
in U.S. Pat. No. 4,194,561. This method involves the use of
placement devices for positioning buoyant ball sealers at a
specific location within the wellbore. These devices are
equipped with means to prevent the upward migration of the
buoyant ball sealers past the placement device. The ball
sealers are seated on the perforations by flowing fluid down the
casing and through the device. These devices are normally used
to selectively close the perforations located at the lowermost
region of the casing.
Another prior art method for selective diversion is
disclosed in U.S. Pat. No. 4,287,952. This method involves the
selective sealing of perforations at the top or bottom of the
1~4~il615
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deviated casing (wherein "top" and "bottom" are identified with
reference to an imaginary plane which is aligned substantially
vertically and extends along the longitudinal axis of the
casing). Other perforations are formed away from these top and
bottom perforations thereby permitting balls of particular
densities to seat on such top or bottom perforations, leaving
the other perforations placed away from these top and bottom
perforations open for fluid communication with a zone to be
treated.
Yet another prior art method of placing ball sealers
onto a casing perforation is disclosed in U.S. Pat. No.
4,195,690. This method involves the placement of a plurality of
balls at a transition region between a first and second fluid.
This method has application in a deviated wellbore also as a
means of negating the effects of gravity/buoyancy forces which
limit the seating capabilities of buoyant and nonbuoyant ball
sealers to those perforations preferentially located on the high
and low side of the pipe, respectively. However, U.S. Pat.
No. 4,195,690 does not teach the number of ball sealers to be
used in sealing at least one perforation in a deviated wellbore
if the balls are transported down at an interface between two
immiscible fluids.
Therefore, there still exists a need for an improved
method of treating a specific zone in a deviated casing without
the need to be concerned about the circumferential location of
the perforations around the casing or about the use of a
lZ4(~615
placement apparatus but, rather, based on more proven diversion
techniques using lightweight ball sealers.
SUMMARY OF TNE INVENTION
Broadly, the present invention comprises transporting a
plurality of ball sealers down a deviated casing at an interface
formed by two immiscible fluids. The number of ball sealers is
greater than the number of perforations desired to be sealed to
the extent that the interface is maintained partially covered
with ball sealers. The plurality of ball sealers is transported
past the perforations such that at least one ball sealer seats
onto a perforation. The leading or first fluid has a density
greater than the ball sealers. The trailing or second fluid has
a density less than the ball sealers and is immiscible in the
first fluid.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is an illustrational view in section of a
deviated well.
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FIG. 2 is an illustrational view in section of the same
deviated well as illustrated in FIG. 1 but further illustrating
the practice of the invention.
FIG. 3 is a schematic of a deviated well illustrating
the geometry associated with the practice of the invention.
FIG. 4 is a schematic of a horizontal cross-section of
a vertical well.
FIG. 5 is a schematic of the deviated well further
illustrating the practice of the invention.
FI5. 6 is a schematic of a horizontal cross-section of
the deviated well.
FIG. 7 is a graph of seating efficiency versus number
of ball sealers at the interface.
DETAIL DESCRIPTION OF THE INVENTION
Referring to FIG. 1, there is shown a deviated wellbore
lO which penetrates an overburden 12 and a subterranean
formation 13 containing petroleum, gas, and mixtures thereof. A
well casing 14 extends through the well and is held in place by
a cement sheath 15. To establish fluid communication between
the formation and the interior of the casing, the casing and
sheath are penetrated to provide a plurality of perforations
lZ4~615
_9_
17. The well may be provided with a packer 18 to isolate
production from formation 13 from the remainder of the string
and with a tubing string 20 which eY.tends from the wellhead at
the surface (not shown) through packer 18. The tubing string is
provided with a suitable flowline (not shown) for the
introduction and withdrawal of fluids to and from the well.
If the well does not have the desired productivity, it
is common practice to treat the well to improve its production
characteristics. This may be accomplished by acidizing,
hydraulic fracturing, or other methods which comprise pumping a
treating material down the casing and into the producing
formation through the perforations 17. As mentioned above, it
is sometimes desirable to selectively close those perforations
through which most fluid is flowing during the treating
operation so that treating fluid is pumped into the formation
adjacent to other perforations in the casing which are less
permeable or damaged.
Prior to illustrating any specific embodiments of this
invention, it is appropriate that the following definitions be
established to clarify the terminology used to describe ball
sealer and fluid density characteristics. Namely, light or low
density fluids refer to fluids having densities less than the
density of the ball sealer. Conversely, dense or heavy fluids
herein refer to fluids having densities greater than the density
of the ball sealer. Similarlyl light, lightweight, or low
density ball sealers refer to ball sealers having a density less
124~ 5
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than the densities of the wellbore fluids. Heavy or dense ball
sealers refer to ball sealers having a density greater than the
densities of the wellbore fluids.
By way of illustrating one embodiment of the present
invention, it will be assumed that the well is an oil production
well which is to be treated by a matrix acidizing operation to
increase the permeability of formation 13 near the wellbore. It
is to be understood, however, that the following description of
such an acidizing operation is merely exemplary in that the
invention may be used in other well-treating procedures, such as
hydraulic fracturing or solvent/surfactant stimulation
treatments.
The acidizing of formation 13 is accomplished by first
pumping through production tubing 20 a dense fluid 21. Dense
fluid 21 would be the treating fluid. After a suitable quantity
of dense fluid is injected, lightweight ball sealers 25 are
introduced in the last few barrels of dense fluid. Then a
suitable quantity of a second light or low density fluid 24 is
introduced. The light fluid is immiscible with the dense
fluid. Since the ball sealers are heavier than the light fluid
24 and lighter than the dense fluid, the balls 25 will gravitate
to the interface 26 between the bottom of the light fluid and
the top of the dense fluid. Since both fluids are immiscible,
the interface 26 is sharp and distinct. The use of such a sharp
and distinct interface is important in the practice of the
invention because it provides a plane or surface across which
lZ4~615
ball sealers can move in a direction normal to gravity. Since
the interface is in intimate contact with the entire
circumference of the interior of the casing, regardless of the
angle of deviation of the casing or the wellbore, ball sealers
are able to seal perforations located at any circumferential
position around the casing.
If the treating fluid is the dense fluid 21 which was
first injected, it is preferred that after a sufficient amount
of light fluid 24 has been introduced into the casing, a
displacement fluid 29 is injected into the casing to completely
displace the previously injected fluids. The displacement fluid
may be a fluid denser than the ball sealers which could be
another treating fluid.
Referring to FIGS. 1 and 2 again, typically the dense
fluid 21 is introduced into the well ahead of the light fluid
and may be referred to as the leading fluid. Similarly, the
light fluid 24 may be referred to as the trailing fluid.
Included in these two classes of fluids (i.e. dense
fluids and light fluids) are any fluids with the requisite
density characteristics. Suitable dense fluids may include acid
solutions such as hydrochloric acid, hydrofluoric acid~ formic
acid, salt-weighted acid solutions, salt-weighted water
solutions, and freshwater, as well as suitable dense hydraulic
fracturing fluids and solvent/surfactant solutions used to
stimulate the formation. Suitable light fluids include field
124~6~S
-12-
crudes, diesel oil, aromatic solvents, light hydrocarbon
condensates, low salinity brines, and fresh water.
The volume of light fluid 24 introduced in the casing
will vary depending on whether the light fluid is for placement
of the balls only or for treatment of the formation also. At a
minimum, the volume of light fluid must be sufficient to permit
the interface to traverse the desired length of perforated
interval before being underrun by a second stage of dense
fluid. This minimum volume is a function of the relative
densities of the light and heavy fluids, the tubing-casing
geometry, the well deviation, the depth and extent of the
perforated interval desired to be sealed, and the pumping rate.
In practicing the invention, a minimum number of ball
sealers 25 should be introduced into the casing 14 to ensure
proper seating in the deviated wellbore and treatment of the
formation 13. The seating efficiency can be maximized by
minimizing the distance that a ball sealer must travel across
the interface. The proximity of a ball sealer to a perforation
is controlled by the number of ball sealers at the i~miscible
interface.
The appropriate number of ball sealers must be injected
in a volume of fluid at the end of the dense fluid stage and/or
the beginning of the light fluid stage that is less than or
equal to the migration volume of the ball sealers from the
surface to the location in the perforated interval desired to be
lZ4q~q6~S
-13-
sealed. This will insure that the ball sealers are at the
interface when it traverses the location in the perforated
interval desired to be sealed.
A broader perspective of the invention may be gained by
comparing previously discussed FIG. 1 with FIG. 2. FIG. 2
illustrates the invention as the interface 26 advances past the
perforations 17. As shown, some of the ball sealers 25 remain
suspended at the interface while the remaining ball sealers have
seated on perforations adjacent the more permeable or undamaged
portions of the formation 13. Light fluid 24 and then
displacement fluid 29 are being injected into the formation
through perforations not sealed.
The embodiment described above may be repeated to carry
out multistage treatments of the formation. For example, the
process may be repeated by using a second stage of treating
fluid as the displacement fluid 29. In this case, the treating
fluid would be followed by light fluids again.
After a suitable number of treatment stages have been
injected into the formation, fluid injection may be stopped to
permit pressure in the well to decrease. The ball sealers which
unseat from perforations will tend to gravitate to the bottom of
the light fluid and thus be less likely to be produced from the
well during production, particularly if the production fluids
are low density fluids.
lZ~ LS
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The ball sealers used in the practice of the invention
would have a density between the light fluid 24 and the dense
fluid 21. Ball sealers suitable for this invention may have an
outer covering sufficiently compliant to conform to the
perforations and have a solid rigid core which resists çxtrusion
into or through the perforations (see, for example, U.S. Pat.
Nos. 4,102,401 and 4,244,425). The ball sealers are
approximately spherical in shape but other geometries may be
used. The density differential between the light and heavy
fluids and the ball sealers is preferably sufficient to allow
the ball sealers to gravitate to the bottom of the light fluid
and/or to the top of the heavy fluid as the fluids flow
downwardly in the casing. In a typical matrix treating process,
the density differential between the light fluid and the ball
sealers is preferably about 0.03 g/cc or more at bottom-hole
conditions. Similarly, the density differential between the
dense fluid and the ball sealers is preferably about 0.03 g/cc
or more at bottom-hole conditions. For example, if the density
of ball sealers is 1.00 g/cc, the dense fluid should have a
density of at least 1.03 g/cc and the light fluid should have a
density less than 0.97 g/cc at bottom-hole conditions. To
achieve this controlled-density situation, the ball sealers may
be constructed specifically to yield the appropriate densities.
As noted above with reference to FIG. 2, the invention
is performed by advancing the interface 26 downwardly past the
perforations 17. In practicing the invention, a minimum number
lZ4~615
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of ball sealers must be injected into the deviated wellbore to
ensure that at least one perforation is sealed.
The minimum number of ball sealers needed to æeal at
least one perforation is related to the percentage of the total
interfacial area occupied by a perforation's area of influence.
Laboratory data, as discussed below, indicate that both the
total interfacial area and a perforation's area of influence
increase by the same factor as the angle of the wellbore from
the vertical increases. Therefore, the minimum number of ball
sealers required to seal at least one perforation is not a
function of the deviated angle of the wellbore; rather, it has
been found to be a function of the inside diameter of the
casing. The minimum number of ball sealers needed to seal at
least one perforation can be approximated by the following
empirical equation:
Minimum Number of Ball Sealers (Nmin) ~ D2/2.4 (1)
where D is the inner diameter of the casing
(in inches).
In other terms, to obtain high seating efficiency,
which is desirable, a minimum number of ball sealers should be
injected which number can be expressed also in terms of the
minimum per cent coverage of the interface (i.e., fraction of
interface covered with one layer of ball sealers--referred to
also as a "monolayer"). The minimum interfacial coverage
required can be approximated by the following equation:
1;~4~i15
-16-
Minimum Per Cent of Interfacial Coverage
(Db)2cos a x 100 (2)
(1-~)2.4
where Db is the diameter of the ball sealer (in inches),
a is the angle of the wellbore from the vertical,
and ~ is the packing porosity of the ball sealers
at the interface.
Reference is made to FIGS. 3-7 for an explanation of
these two equations.
When a is equal to 0, the casing 14 is vertical and
the horizontal cross-sectional interfacial area is a circle
whose area is ~D2/4 (see FIG 4). When a is between 0
and 90 (see FIG. 3) the horizontal cross-sectional interfacial
area is an ellipse whose area is ~ab, where 2a is the major
axis (D/cos a) and 2b is the minor axis (D). Therefore, the
elliptical area is defined to be:
Interfacial elliptical area =
4 cos (3)
Thus, the number of balls to form a complete monolayer at the
interface may be approximated as:
(No. of Interfacial (1-~ /4)(D2tcos a)
Ball Sealers)Monolayer=
~4 (Db)
where Db is the diameter of the ball sealer (in
inches), and ~ is the porosity.
'l 24(~15
-17-
For ~ = 0.30 (empirical) and Db = 7/8 inches, equation (4)
reduces to:
(No. of interfacial /0.70 D\2 0.91D (5)
Ball Sealers)Monolayer = _
S ~cos a cos a
Referring to FIG. 4, a perforation 17 is indicated on
the circumference of casing 14. FIG. 4 is a horizontal
cross-section taken across a vertical wellbore. Adjacent to
perforation 17 is a semi-circular area identified as areal
extent 40. This defines the area of influence ("capture
influence") that the perforation will affect as the interface
traverses the perforation. The circumferential component on
casing 14 of the capture influence of areal extent 40 is
identified as Di. The radial component on casing 14 of the
capture influence of areal extent 40 is 1/2 Di.
Referring now to FIGS. 5 and 6, the casing 14 is shown
deviated. In FIG. 5 a perforation 17 is located along the major
axis of the resulting elliptical horizontal cross-sectional area
(see FIG. 6). Another perforation 18 is located along the minor
axis of the resulting elliptical horizontal cross-sectional area
shown in FIG. 6.
The circumferential components on casing 14 of the
capture influence of perforations 17 and 18 depends on their
location on the ellipse. In the case of the perforation 17 in
FIGS. 5 and 6, the circumferential component of the capture
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influence of areal extent 42 is equal to Di/cos a, where a
is the angle of the wellbore in degrees with respect to the
vertical. The circumferential component of the capture
influence of areal extent 44 is equal to Di, which is similar
to the circumferential component of the capture influence of
areal extent 40 shown in FIG. 4. The radial component of the
capture influence of areal extent 42 is equal to Di/2. The
radial component of the capture influence of areal extent 44 is
equal to (l/2)(Ditcos a).
In order for a ball sealer to seat on a perforation,
it must be within the capture influence of the particular areal
extent. Accordingly, the size of the capture influence for
areal extent 40 shown in FIG. 4 is approximately equal to
~ Di /8. The size of the capture influence for areal
extent 44 as shown in FIG. 6 is approximately equal to
[~ Di2/8)~ /cos a. Since the area of the circle shown
in FIG. 4 is ~ D2/4 and the area of the ellipse shown in
FIG. 6 is ~(~ D2/4)] /cos a, the ratio of the areas of
capture influence to the areas of the interior of the casing in
FIGS. 4 and 6 is approximately equal to:
Alnfluence ~ ~ ) (___z_~)
Acasing D circle D ellipse
Thus, in solving these two equations
Ainfluence/Aca5ing F/D where F ~ Di 2/2
1',Z4q;~15
~19-
F has been determined empirically by laboratory
data. The results from the laboratory experiment, as
discussed below, indicate that the factor F lies between
about l.8 and 2.4, preferably about 2.4.
From probability theory, the miminum number of
ball sealers is directly related to the ratio of the
Acasing/Ainfluence. In other words, the minimum number of
ball sealers is directly related to the percentage of the total
area of the casing (Ac) which is occupied by the area of
influence or areal extents (Ai). Consequently,
Ac D2 D2
Minimum Number of Balls
Ai F 2.4
Referring back to equation (4) and converting the minimum number
of balls to a percentage of interfacial coverage:
Minimum Per cent of Interfacial Coverage
D /F
(l-~)(~14)(D /cos ~) X lOO
(~/4)(Db) 2
This then reduces to equation (2) when F = 2.4.
Laboratory Experiments
Laboratory experiments were conducted using a lucite
wellbore model having an outside diameter of 7 inches and an
inside diameter of 6 inches. Initially, the wellbore model waS
1~(36~5
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inclined at 60 to the vertical. This first experiment indicated
that it was preferable that the interface be formed between two
immiscible surfaces for optimum movement of the balls laterally
along the interface towards the perforations. This first
experiment also indicated that it was not necessary that there be
a substantially complete monolayer of ball sealers at the
interface following advancement past the perforations as
originally contemplated. Subsequent experiments were conducted
with the same model but inclined at 45 and 75 to better define
the operating efficiency of the invention. The data for the 45
test are shown in FIG. 7. In all these tests, the first fluid was
tap water (specific gravity of 1.0) and the second light fluid was
a refined oil with mutual solvent (Isopar with 10%-20% C7610;
specific gravity of 0.80-0.85). Consequently, a very
distinguishable interface was formed. The balls were 0.875 inches
in diameter and had a specific gravity of 0.90. The displacing
fluid following ~he oil was tap water.
Referring to FIG. 7, the fluids were pumped into the
lucite model at rates of 10, 20, 30 and 40 gallons per minute
(gpm). Flow out the bottom of the model was controlled in order
to obtain perforation flow rates of 10 or 20 gpm. The tests
indicate that for an interior casing diameter of 6 inches, a
minimum nu~ber of 15-20 balls is required in order to seal at
least one perforation. This resulted in the factor F being
between 1.8 and 2.4 since the minimum number of balls is inversely
related to the Ainfluence/AcaSing. Thus, the minimum number
124531615
-21-
of balls approximately equals D2/F or F ~ D2/N
referring back to equation (1) above.
Referring to FIG. 7, it can be seen that the efficiency
of the ball sealers increases significantly upon the introduction
of at least 15-20 ball sealers. This number represents the
general range of the minimum number of balls required to achieve a
high seating efficiency.
A number of conclusions can be made based on the
experiments. If the flow rate through the perforations is
constant, seating efficiency will decrease as the flow rate past
the perforations increases. If the flow rate past the
perforations is constant, the seating efficiency will increase as
the flow rate through the perforations increases. There is no
statistically significant difference between data from the 45 and
75 tests. Consequently, only the 45 data are shown.
Field Example
The following field example illustrates a specific
procedure for performing the present invention. For this
hypothetical example, a well is drilled in an oil- and
gas-bearing, carbonate formation. The well is deviated 30 from
the vertical through the productive formation. It is completed,
generally as shown in FIGS. 1 and 2, with a 7-in.-OD, 32-lb/ft
production casing (6.094-in. ID) to a total measured depth of 5120
ft. A packer is run into the casing on 2-7/8-in.-OD, 6.5-lb/ft
production tubing (2.441-in. ID) and set at the 5000 ft depth. An
1~4'~3~15
interval located at the 5050-5100 ft level is perforated with 100
holes. The perforations are randomly oriented around the
circumference of the production casing.
To stimulate oil production, the well is to be acidized
with 28% hydrochloric acid (HCl) having an approximate density of
1.14 g/cm . The maximum allowable injection rate of the acid
solution down the production tubing for matrix acidization is
determined to be 2.0 barrels per minute (sPM). Injectio~ rates
above 2.0 BPM may fracture the formation.
Ball sealers having a 7/8-in. diameter and a density of
1.10 g/cm3 are used to restrict fluid flow through the perfora-
tions having the least resistance to fluid flow. The rising
velocity of the ball sealers in 28% HCl is determined to be
approximately 30 ft/min. At 2 BPM, the downward velocity of the
28% HCl is about 345 ft/min in the production tubing and about 56
ft/min in the production casing. Consequently, the ball sealers
could be transported down the production tubing and casing to the
perforated interval. However, without using a treating technique
as provided by this invention, these balls would only be effective
in sealing perforations located on the high side of the wellbore.
The practice of this invention may be carried out in
accordance with the following sequence of steps:
1. Inject a 1.20 g/cm aqueous brine containing a
NaCl - CaC12 ~ixture to fill the wellbore (optional);
1~4~6~5
2. Inject 100 barrels of the 28% HCl (1.14 g/cm3)
into the production tubing;
3. Inject 10 barrels of diesel oil having a density of
0.85 g/cm3 and containing 65 ball sealers in the first 5
barrels of diesel oil;
4. Inject 100 barrels of 2890 HCl into the production
tubing;
5. Inject field crude oil into the tubing to displace
the HCl to the perforations.
In practicing the above procedure, the ball sealers will
sink in the diesel, but float in the 28% HCl. During Steps 3 and
4 the balls will migrate to and accumulate at the diesel-acid
interface. The volume of diesel in Step 3 is sufficient to
prevent the second stage of 28% HCl (Step 4) from falling
completely through the diesel and reaching the stable, immiscible
interface before the interface has traversed the perforated
interval. The diesel volume is a function of completion geometry
and injection rate (assumed to be 2.0 BPI~ in this example).
With reference to FIGS. 1 and 2, the 28% HCL injected in
Step 2 is dense fluid 21; the diesel oil injected in Step 3 is
light fluid 24; and the 28% HCL injected in Step 4 is displacement
fluid 29. It will be obvious to anyone skilled-in-the-art based
on this disclosure that Steps 2 and 3 above may be repeated
several times in order to provide multiple applications of ball
sealers.
615
-24-
In this hypothetical example, it is desired initially to
treat half of the interval (i.e., 50 perforations), to
subsequently seal the treated perforations, and finally to treat
the remaining 50 perforations. Therefore, the number of ball
sealers (Step 3) is determined as the number of perforations
desired to be sealed (50 in this example) plu the minimum number
of balls that must be positioned at the interface to achieve high
seating efficiency. In this example, the minimum number of ball
sealers is 15:
[D(in.)] (6.094)
(Interface Balls) ~ ~ ~ 15
min
2.4 2.4
The balls are injected in a volume of fluid (i.e., 5
barrels) at the beginning of the diesel stage that is less than
the migration volume (at 2.0 BPM) of the ball sealers from the
surface to the top of the perforated interval at 5,050 ft. This
allows the balls to migrate to the interface. If equipment
limitations preclude injecting ball sealers at the required rate
(balls/min), the pump rate may be decreased or a shutdown period
may be included in the program which provides additional time for
the balls to migrate to the interface. However, a lower pumping
rate necessitates a greater volume of diesel to prevent
underrunning by the second stage of HCl.
-25-
The second stage of HCl (Step 4) treats the perforations
that have not been sealed (i.e., 50 perforations). The treatment
is displaced with sufficient field crude to overdisplace all acid
into the formation leaving the wellbore filled with the light
field crude. As a result, upon completion of the above procedure,
and upon relieving the differential pressure across the
perforations, the ball sealers sink to the rathole. With the ball
sealers in this location, the likelihood of producing ball sealers
with the formation fluids is minimized.
Even though the invention has been disclosed in terms of
producing an oil and gas well, it will be appreciated by those
skilled in the art based on this disclosure that the invention may
be used as described in a water-injection well that is adjacent to
a producing well. A water-injection well is used to stimulate the
reservoir and enhance production from the producing well. Such a
water-injection well may be deviated and it may be deairable to
seal only certain perforations using lightweight ball sealers and
multiple density fluids as described herein.
Furthermore, while embodiments and applications of the
method of the present invention have been shown and described, it
will be apparent to those skilled in the art that many more
modifications are possible without departing from the inventive
concepts herein described. The invention, therefore, is not to be
restricted except as is necessary by the prior art and by the
spirit of the appended claims.
