Note: Descriptions are shown in the official language in which they were submitted.
CA 02895507 2016-10-07
TITLE: DOWNHOLE TOOLS
HAVING NON-TOXIC DEGRADABLE ELEMENTS
AND METHODS OF USING THE SAME
BACKGROUND OF THE INVENTION
[02] This specification relates to the field of mineral and hydrocarbon
recovery,
and more particularly to the use of high-molecular weight polyglycolic acid as
a primary
structural member for a degradable oilfield tool.
[03] It is well known in the art that certain geological formations have
hydrocarbons, including oil and natural gas, trapped inside of them that are
not
efficiently recoverable in their native form. Hydraulic fracturing ("fracking"
for short) is a
process used to fracture and partially collapse structures so that economic
quantities of
minerals and hydrocarbons can be recovered. The formation may be divided into
zones, which are sequentially isolated, exposed, and fractured. Fracking fluid
is driven
into the formation, causing additional fractures and permitting hydrocarbons
to flow
freely out of the formation.
[04] It is also known to create pilot perforations and pump acid or other
fluid
through the pilot perforations into the formation, thereby allowing the
hydrocarbons to
migrate to the larger formed fractures or fissure.
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[05] To frac multiple zones, untreated zones must be isolated from already
treated zones so that hydraulic pressure fractures the new zones instead of
merely
disrupting the already-fracked zones. There are many known methods for
isolating
zones, including the use of a frac sleeve, which includes a mechanically-
actuated
sliding sleeve engaged by a ball seat. A plurality of frac sleeves may be
inserted into
the well. The frac sleeves may have progressively smaller ball seats. The
smallest frac
ball is inserted first, passing through all but the last frac sleeve, where it
seats. Applied
pressure from the surface causes the frac ball to press against the ball seat,
which
mechanically engages a sliding sleeve. The
pressure causes the sleeve to
mechanically shift, opening a plurality of frac ports and exposing the
formation. High-
pressure fracking fluid is injected from the surface, forcing the frac fluid
into the
formation, and the zone is fracked.
[06] After that zone is fracked, the second-smallest frac ball is pumped into
the
well bore, and seats in the penultimate sleeve. That zone is fracked, and the
process is
continued with increasingly larger frac bails, the largest ball being inserted
last. After all
zones are fracked, the pump down back pressure may move frac balls off seat,
so that
hydrocarbons can flow to the surface. In some cases, it is necessary to mill
out the frac
ball and ball seat, for example if back pressure is insufficient or if the
ball was deformed
by the applied pressure.
[07] Another style of frac ball can be pumped to a different style of ball
seat,
engaging sliding sleeves. The sliding sleeves open as pressure is increased,
causing
the sleeves to overcome a shearing mechanism, sliding the sleeve open, in turn
exposing ports or slots behind the sleeves. This permits the ports or slots to
act as a
conduit into the formation for hydraulic fracturing, acidizing or stimulating
the formation.
[08] It is known in the prior art to manufacture frac balls out of carbon,
composites, metals, and synthetic materials such as nylon. When the frac ball
has
fulfilled its purpose, it must either be removed through fluid flow of the
well, or it must be
destructively drilled out. Baker Hughes is also known to provide a frac ball
constructed
of a nanocomposite material known as "In-Tallic." In-Tallic balls are
advertised to begin
dissolving within 100 hours in a potassium chloride solution.
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[09] In some embodiments, Applicants describe structural elements as being
degradable and being homogenous and/or non-composite. Homogenous and non-
composite mean that the structural element does not contain a mixture of two
or more
different materials. It means that the structural element is not a mixture of
physically
discrete or chemically discrete components, and that it has a substantially
uniform
texture throughout. It is not layered; it does not combine resin and fibers,
even if they
are the same chemical compound. The rate of degradation is the same
throughout, it
does not contain material that has a first rate of degradation with a material
that has a
second rate of degradation. A component may be degradable and homogenous where
it is made entirely of a single composition, such as polyglycolic acid, that
may be a part
chrystalline and part amorphous.
[10] Another style of frac ball can be pumped to a different style of ball
seat,
engaging sliding sleeves. The sliding sleeves open as pressure is increased,
causing
the sleeves to overcome a shearing mechanism, sliding the sleeve open, in turn
exposing ports or slots behind the sleeves. This permits the ports or slots to
act as a
conduit into the formation for hydraulic fracturing, acidizing or stimulating
the formation.
SUMMARY OF THE INVENTIONS
[11] in one exemplary embodiment, a plurality of mechanical tools for down
hole use are described, each comprising substantial structural elements made
with high
molecular weight polyglycolic acid (PGA). The PGA of the present disclosure is
hard,
millable, substantially incompressible, homogenous, and capable of being used
as the
material of downhole tools. The PGA material of the present disclosure begins
to lose
structure above about 136 F in fluid. Under a preferable thermal stress of at
least
approximately 250 F the PGA material substantially loses its structure within
approximately 48 hours. As the structure breaks down, the PGA tools lose
compression
resistance and structural integrity. After the structure breaks down, the
remaining
material can be safely left to hinripgrarIR over a period of several months.
The products
of biodegradation, are substantially glycine, carbon dioxide, and water, and
are non-
toxic to humans. PGA tools provide the advantage of being usable downhole and
then,
when their function is accomplished, removed from the well bore through
passive
degradation rather than active disposal. The disclosed downhole tools made of
PGA
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material can be initially used as conventional downhole tools to accomplish
conventional downhole tool tasks. Then, upon being subjected to downhole
fluids at the
described temperatures, for the described times, the PGA elements lose (1)
compression resistance and structural integrity which causes them to cease
providing
their conventional downhole tool tasks, followed by (2) passive degradation
into
environmentally-friendly materials. This permits them to be left in the well
bore rather
than having to be milled out or retrieved. Other benefits and functions are
disclosed.
[12] In another embodiment, a method of producing hydrocarbons from
multiple zones from a well is provided, the well having a wellbore with a
wellbore casing,
the method comprising the following steps. Providing a first set of frac
plugs, each with
an inner conduit, adapted to fit within the wellbore casing, and a first set
of frac balls,
each frac ball adapted to fit within one of the provided frac plugs and to
block the frac
plug's inner conduit, wherein at least one of either the frac ball or the frac
plug in each
frac plug and frac ball combination is comprised of a homogenous, non-
metallic,
degradable material that will begin to degrade in a fluid at a temperature of
at least
above about 150 F within about one month of being exposed to downhole fluid
in the
casing, resulting in a sufficient loss in mass that the frac plug and frac
ball combination
ceases to isolate zones. The method includes perforating the casing and
fracing a first
lower zone; running a bottom hole assembly comprising at least a first frac
plug and a
setting tool into the casing to a first setting depth and setting the first
plug at a first
setting depth in the lower zone; inserting a first ball down the casing until
it seats within
the first plug and seals its inner conduit, isolating the first lower zone,
then perforating
the casing at a second lower zone above the first set frac plug and fracing
the second
lower zone. The method repeats the running, setting, inserting, seating,
sealing, and
isolating steps above the second lower zone with an additional frac plug and
frac ball
from the first set of degradable frac plug and frac ball combinations. The
wellbore within
the lower zone in one embodiment has fluid at a temperature of at least about
150 F
and the first set of frac plugs in the lower zone are not drilled out, but
rather degrade
within about one month of being exposed to the downhole fluid in the wellbore
casing
resulting in a sufficient loss in mass that each frac plug and frac ball
combination therein
ceases to isolate zones.
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[13] In another embodiment, Applicants provide a downhole tool for engaging a
wellbore casing of a hydrocarbon well, the downhole tool comprising structural
elements
including a cylindrical mandrel having an outer surface and an inner surface,
the inner
surface defining an inner conduit, and also structural elements disposed on
the outer
surface of the mandrel, at least some configured to engage the inner walls of
the
wellbore casing in a set position and some others to drive those configured to
set into
the set position from a run in position. At least some of the structural
elements
comprise a non-composite degradable material that will begin degradation at
fluid
temperatures above about 150 F and will degrade into environmentally harmless
products.
[14] In another embodiment, Applicants provide a device for use in a well
comprising a borehole extending from a surface location and penetrating a
hydrocarbon
bearing interval and with a casing string in the borehole having a minimum
internal
diameter. The device may comprise a flapper valve assembly and a tubular
housing
with an inner diameter, providing part of the casing string and being at a
location
between the hydrocarbon bearing interval and the surface location. A flapper
valve
engages the tubular housing and is moveable between a first operative position
allowing
upward and downward flow through a casing string and tubular housing and a
second
operative position allowing upward flow and preventing downward flow through
the
casing and tubular housing, the flapper valve member being substantially
homogenous,
nonmetallic and comprised of a degradable material, degradable in acidic or
non-acidic
fluids at temperatures above about 150 F.
[15] In another embodiment, Applicants provide a method of temporarily
plugging a section of casing at a well at a well site with degradable frac
balls, including
providing a set of polyglycolic acid ("PGA") frac balls to the well site. The
balls in the set
of balls have preselected diameters, at least some of the balls have
preselected
constant incremental diameter differences. The ball diameters of the balls in
the set of
balls are selected through use of ball degradation rate factors, and estimated
formation
conditions in the well, so at least some of the balls within the set of balls
are appropriate
for temporarily plugging a first frac plug and a second frac plug within the
section of
casing at the well. The steps include determining a location in the well for
positioning
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the first frac plug and determining a location in the well for the second frac
plug, the
second frac plug being located above the first frac plug. One may estimate
formation
conditions at the location for positioning the first frac plug in the well;
including at least
formation temperature, and determine a desired duration for the first frac
plug to be
plugged. One may estimate formation conditions at the location for positioning
the
second frac plug in the well, including at least formation temperature, and
determine a
desired duration for the second frac plug to be plugged. The steps include
determining
appropriate ball size for a first frac plug seat size and appropriate ball
size for a second
frac plug seat size using PGA ball degradation rate factors, and well
conditions at the
first and second frac plugs, and the desired duration for the first and second
frac plugs
to be plugged. A first frac ball for the first frac plug should provide
sufficient overlap to
withstand the estimated maximum pressure. One may insert the first frac ball
into the
well casing, pumping the first frac ball down the well until its seats with
the first frac
plug, perforate, and frac the zone, then set, plug, perforate, and frac high
zones.
[16] Applicants provide an assembly for use in at least two downhole isolation
valves in production operations in a well, comprising a set of homogenous, non-
metallic
degradable frac balls, the balls in the set of balls having preselected
diameters, at least
some of the balls having preselected constant incremental diameter
differences, the ball
diameters of the balls in the set of balls being selected through use of ball
degradation
rate factors and estimated formation conditions at the downhole isolation
valves, so at
least some of the balls within the set of balls are appropriate for
temporarily plugging a
first isolation valve and a second isolation valve within the well.
[17] Applicants further provide a sub for use downhole in a hydrocarbon well,
the sub comprising at least one disk having a body and a perimeter; and a
support
structure having an inner conduit, the support structure for engaging the at
least one
disk at the perimeter of the disk. wherein the disk is dimensioned in an
initial condition
to block the inner conduit within the support structure, the disk comprised of
a
homogenous, non-metallic, degradable material, which is capable of degrading
in
down hole fluid.
[18] Applicants further provide a device for setting a downhole tool against
the
inner diameter of a downhole casing of a well. The device may comprise a
cylindrical
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slip having an outer section comprised of teeth and an inner section comprised
of an
inner wall, wherein the teeth are comprised of a metallic material. At least
part of the
inner walls are comprised of a non-metallic, homogenous, degradable material
that will
begin to degrade when exposed to a downhole fluid at a temperature of at least
at about
150 F so that when used in well with downhole fluid at a temperature of at
least 150 F,
the inner walls detach from the teeth and degrade into smaller fragments
within a
predetermined time which do not substantially interfere with completing the
well.
[19] Applicants further provide an isolation sub for use in subterranean
hydrocarbon recovery comprising:a rigid casing configured to interface with a
casing
string or tubing string; and a plurality of ports disposed along the
circumference of the
rigid casing, each port having seated therein a retaining plug, each retaining
plug having
seated therein a plug consisting essentially of a degradable material, such as
polyglycolic acid.
[20] In addition, Applicants provide multiple settable downhole tools, with
setting elements engaging a mandrel, the mandrel defining an inner conduit and
supporting a seat; a non-composite body is configured to engage the seat in an
initial
configuration. The non-composite body is substantially stable in a dry
condition at
ambient temperature, and, when exposed to a downhole fluid having a
temperature of
at least about 136 F, the non-composite body will change to a subsequent
configuration that does not engage the seat. In its changed configuration, it
is then
capable of passing through the seat and inner conduit. The non-composite body,
in one
embodiment, is prepared from polyglycolic acid (PGA). The non-composite body
may
be spherical, and is in the range of between about 0.750 inches to about 4.625
inches in
diameter. The non-composite body may be homogenous; and will degrade into
environmentally non-toxic substances within up to about one month of being
exposed to
the downhole fluid.
BRIEF DESCRIPTION OF THE DRAWINGS
[21] FIG_ 1 is a cutaway side view of a frac sleeve actuated with a PGA frac
ball.
[22] FIG. 2 is a cutaway side view of a mechanical set composite cement
retainer with poppet valve, having PGA structural members.
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[23] FIG. 3 is a cutaway side view of a wireline set composite cement retainer
with sliding check valve, having PGA structural members.
[24] FIG. 4 is a cutaway side view of a mechanical set composite cement
retainer with sliding sleeve check valve, having PGA structural members.
[25] FIG. 5 is a cutaway side view of a PGA frac plug.
[26] FIG. 6 is a cutaway side view of a temporary isolation tool with PGA
structural members.
[27] FIG. 7 is a cutaway side view of a snub nose composite plug having PGA
structural members.
[28] FIG. 8 is a cutaway side view of a long-range PGA frac plug.
[29] FIG. 9 is a cutaway side view of a dual disk frangible knockout isolation
sub, having PGA disks.
[30] FIG. 10 is a cutaway side view of a single disk frangible knockout
isolation
sub.
[31] FIG. 11 is a cutaway side view of an underbalanced disk sub having a
PGA disk.
[32] FIG. 12 is a cutaway side view of an isolation sub having a PGA disk.
[33] FIGS. 13-130 are detailed views of an exemplary embodiment of a
balldrop isolation sub with PGA plugs.
[34] FIG. 14 is a cutaway side view of a PGA pumpdown dart.
[35] FIG. 15 illustrates a time/temperature test graph results for a 3 inch OD
PGA ball at 275 F.
[36] FIG. 16 illustrates reduction of the Magnum PGA ball in diameter in
inches
per hour at temperatures from 100 F to 350 F.
[37] FIG. 17 illustrates integrity versus diameter for Applicant's PGA balls,
subject to pressures between 3000 to 15,000 pounds, ball diameters 1.5 to 5
inches
with a 1/8 inch overlap on the seat.
[38] FIG. 18 is a time/pressure curve for Applicant's PGA ball to .25 inches
in
diameter taken to a pressure initially 8000 psi, held for 6 hours, and
pressure released
after 6 hours.
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[39] FIG. 19 is a side elevational view; partially cut away of a 51/2 inch
snub
nose ball drop with items designated numbers 1 through 15 for that Figure
only.
[40] FIGS. 19A and 19B show pressure set and pressure tests of a PGA
composite downhole tool.
[41] FIG. 20 is a schematic cross-sectional view of an exemplary environment
showing a wellbore casing extending into a subterranean hydrocarbon formation.
[42] FIGS. 21A and 21B illustrate cross-sectional/exterior views of a downhole
tool having degradable elastomeric elements.
[43] FIG. 22A is a cross-sectional view showing the combined slip on the left,
with the degradable portion only shown on the right.
[44] FIG. 22B is a cross-sectional view of the degradable portion of the slip;
and FIG. 22C is a front elevational view of the slip having degradable and non-
degradable components.
[45] FIG. 22D is a cross-sectional side view of another embodiment of a slip
having metallic and degradable parts or portions.
[46] FIGS. 23A, 23B, and 23C illustrate two cross-sectional views and a front
elevational view of another embodiment of a slip comprising non-degradable
metallic
teeth inserts in a degradable body.
[47] FIGS. 24A and 24B are cross-sectional views of a flapper valve assembly
with the flapper valve in a closed or down position Fig. 24A; FIG. 24B in an
up or
opened position.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[481 One concern in the use of frac balls in production operations is that the
balls themselves can become problematic. Because it is impossible to see what
is
going on in a well, if something goes wrong, it is difficult to know exactly
what has gone
wrong. It is suspected that prior art frac balls can sometimes become jammed,
deformed, or that they can otherwise obstruct hydrocarbon flow when such
obstruction
is not desired.
[49] One known solution to the problem of frac balls obstructing flow when
obstruction is not desired is to mill out the prior art frac balls and the
ball seats. But
milling is expensive and takes time away from production. Baker Hughes has
9
introduced a nanocomposite frac ball called ln-Tallic. In-Tallic0 balls will
begin to
degrade within about 100 hours of insertion into the well, in the presence of
potassium
chloride.
[50] Polyglycolic (PGA) acid is a polyester of glycolic acid. PGA has been
shown to have excellent short-term stability in ambient conditions. Kuredux ,
and in
particular Kuredux0 grade 100R60, is a biodegradable PGA with excellent
mechanical
properties and processability. Frazier, et al. have identified a method of
processing
Kuredux0 PGA resin into mechanical tools for downhole drilling applications,
for
example for hydrocarbon and mineral recovery and structures and methods for
using
them.
[51] The Applicant has made and tested PGA frac balls of the present
disclosure by leaving them in room temperature tap water for months at a time.
After
two months, the PGA frac balls showed no signs of substantial degradation or
structural
changes. Applicant's PGA frac balls show no appreciable sign of degradation in
ambient moisture and temperature conditions over a period of at least one
year.
[52] In one test of an exemplary embodiment, a 3.375-inch PGA frac ball
withstood about 6,633 psi before structural failure. A 2.12-inch frac ball
withstood
14,189 psi before failing. A 1.5-inch in frac ball withstood at least 15,000
psi for 15
minutes without failing. A failure point of the 1.5-inch frac ball was not
reached because
the test rig was not able to exceed 15,000 psi. Thus, a PGA frac ball is
suitable for high
pressure downhole hydrocarbon recovery operations, typically frac operations.
[53] PGA frac balls can be pumped down a well bore from the surface.
Typically, the initial pumping fluid is approximately 50 to 75 Fahrenheit,
which condition
does not have any appreciable effect on the short-term structural integrity of
the frac
ball. Bottom hole temperatures are known to increase with depth, as shown, for
example, in Figure 3 of Comprehensive Database of VVellbore Temperatures and
Drilling Mud Weight Pressures by Depth for Judge Digby Field, Louisiana, Open-
File
Report 2010-1303, U.S. Department of the Interior, U.S. Geological Survey. The
Department of Interior Figure 3 chart shows a relatively
linear line temperature vs. depth relationship from about 75 F at about 4,500
feet to
about 400 F at about 24,000 feet. South Texas oil wells typically have depths
from
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about 5,000 to 11,000 feet. When fracking operations commence, however, the
higher
fracking pressures cause the temperature of the downhole fluid to rise
dramatically.
The PGA frac ball performs as a conventional frac ball, sealing against the
bridge plug
seat to block the well bore. When fracking operations commence, however, the
higher
fracking pressures cause the temperature of the downhole fluid to rise
dramatically.
Downhole production fluid temperatures of South Texas wells typically range
from 250
F to 400 F. Temperature ranges vary around the world, in different formations,
conditions, and procedures and thus may be higher or lower at other locations
and
conditions and procedures. Once the PGA frac ball is exposed to the higher
temperature and pressure conditions of the fracking operation, it first
continues to
function as a conventional frac ball, sealing against the bridge plug's seat
to block the
fracking operation while it begins to lose its structural integrity.
Sufficient structural
integrity is maintained during the fracking operation for the PGA frac ball to
continue to
function as a conventional frac ball. After the fracking operation ends, the
PGA frac ball
deteriorates, loses its structural integrity, passes through the bridge plug
seat, and
ceases to block the well bore.
[54] After pressure testing, a 140 g sample was placed in water at 150 F for
four days. After four days, the mass had decreased to 120 g. In a second test,
a 160 g
sample was placed in water at 200 F for four days. After four days, the mass
of the
sample had decreased to 130 g. Acids may expedite dissolution. Kureha
Corporation
has provided the following formula for estimating single-sided degradation of
molded
PGA from thermal stress alone, measured in mm/h:
Amm = -0.5exp (23.654 - 9443/K)
[55] These time spans are consistent with the times at which conventional frac
balls are drilled out, after their fracking operation blocking function has
been
accomplished. Therefore, the PGA frac ball can be used as a conventional frac
ball and
perform the fracking operation blocking function of a conventional frac ball,
but can then
be left in the well rather than drilling it out or other intervention by the
operator. In an
exemplary application, a series of frac balls is used in a fracking operation.
Some prior
art frac balls have sometimes stuck in their ball seat. The PGA frac ball does
not stick
in its ball seat. After they perform their fracking operation function, the
frac balls begin
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to lose structural integrity, their volumes decrease slightly and they pass
through their
respective ball seats and move toward the toe of the well bore. The frac balls
each
continue to lose structural integrity until they each eventually form a soft
mush without
appreciable crystalline structure. This material can be left downhole without
concern.
Over a period of months, the PGA material biodegrades to environmentally
friendly
fluids and gases. In one exemplary embodiment, PGA frac balls substantially
lose
structural integrity in approximately 48 hours in a well with an average
temperature of
approximately 250 F, and completely biodegrades over several months.
[56] It is believed degradation of the PGA in downhole conditions is primarily
accomplished by random hydrolysis of ester bonds which reduces the PGA to
glycolic
acid, an organic substance that is not considered a pollutant and is not
generally
harmful to the environment or to people. Indeed, glycolic acid is used in many
pharmaceutical preparations for absorption into the skin. Glycolic acid may
further
breakdown into glycine, or carbon dioxide and water. For example, in one test,
after 91
days in fluid at 2500F, the PGA ball degraded to less than 90% of its initial
weight and
had biodegradability equal to cellulose subjected to similar conditions. Thus,
even in
the case of PGA mechanical tools that are ultimately drilled out, the remnants
can be
safely discarded without causing environmental harm.
[57] Processing of the PGA material comprises in one embodiment obtaining
appropriate PGA, extruding it into machinable stock, and machining it into the
desired
configuration. In one embodiment, Kuredux brand PGA is purchased from the
Kureha
Corporation. In an exemplary embodiment, grade 100R60 PGA is purchased from
Kureha Corporation through its U.S. supplier, Itochu in pellet form. The
pellets are
melted down and extruded into bars or cylindrical stock. In one embodiment,
the
extruded Kuredux PGA resin bars are cut and machined into up to 63 different
sizes of
PGA balls ranging in size from 0.75 inches to 4.625 inches in 1/16-inch
increments. In
another embodiment, the balls are machined in 1/8 inch increments. In a
preferred
embodiment, the balls are milled on a lathe. The 63 different sizes correspond
to
matching downhole tool sliding sleeves. The smallest ball can be put down into
the well
first and seat onto the smallest valve. The next smallest ball can be pumped
down and
seat on the second smallest seat, and so forth. These ranges and processing
methods
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are provided by way of example only. PGA frac balls smaller than 0.75 inches
or larger
than 4.625 inches and with different size increments can be manufactured and
used.
Injection molding or thermoforming techniques known in the art may also be
used.
[58] In an exemplary embodiment of the present invention as seen in Fig. 1, a
well bore 150 is drilled into a hydrocarbon bearing formation 170. A frac
sleeve 100
inserted into well bore 150 isolates the zone 1 designated 162 from zone 2
designated
164. Zone 1 and zone 2 are conceptual divisions, and are not explicitly
delimited except
by frac sleeve 100 itself. In an exemplary embodiment, hydrocarbon formation
170 may
be divided into up to 63 or more zones to the extent practical for the well as
is known in
the art. Zone 1 162 has already been fracked, and now zone 2 164 needs to be
fracked. PGA frac ball 110, which has an outer diameter selected to seat
securely into
ball seat 120, is pumped down into the well bore 150. In some embodiments,
frac
sleeve 100 forms part of the tubing or casing string.
[59] Frac sleeve 100 includes a shifting sleeve 130, which is rigidly engaged
to
ball seat 120. Initially, shifting sleeve 130 covers frac purls, 140. When PGA
frac ball
110 is seated into ball seat 120 and high-pressure fracking fluid fills well
bore 150,
shifting sleeve 130 mechanically shifts, moving in a down-hole direction. This
shifting
exposes frac ports 140, so that there is fluid communication between frac
ports 140 and
hydrocarbon formation 170. As the pressure of fracking fluid increases,
hydrocarbon
formation 170 fractures, freeing trapped hydrocarbons from hydrocarbon
formation 170.
[60] In an alternative preferred embodiment, a frac ball 110 is pumped down
into the wellbore, seated in a ball seat at the lower end of the well, and
pressure is
applied at the surface of the well, or other point about the casing, to volume
test the
casing. This enables a volume test on the casing without intervention to
remove the
frac ball 110, which naturally biodegrades.
[61] Frazier, et al., have found that PGA frac balls made of Kuredux PGA
resin will begin to sufficiently degrade in approximately 48 hours in aqueous
solution at
approximately 250 F so that the PGA frac ball will cease to be held upon its
seat and
instead pass through the seat to unblock the well bore. The substrate PGA
material has
a crystalline state with about a 1.9g/cm3 density and an amorphous state with
an about
1.5g/cm3 density. It is believed that the described PGA frac ball, when pumped
down
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the well, begins in a hard, semi-crystalline, stable state and that its
immersion in hot
downhole fluid, at least as hot as 136 F, causes the PGA frac ball to begin
change from
its hard partly crystalline state into its more malleable amorphous state. It
is believed
that the frac ball in the hot downhole fluid may also be losing exterior
surface mass as it
hydrolyzes or dissolves. These processes both reduce the frac ball's diameter
and
make the serially-revealed outer material of the frac ball more malleable. It
is believed
the degradation of PGA and downhole conditions has two stages. In the first
stage,
water diffuses into the amorphous regions. In the second stage, the
crystalline areas
degrade. Once serious degradation begins, it can progress rapidly. In many
cases, a
mechanical tool made of PGA will experience sudden mechanical failure at an
advantageous time after it has fulfilled its purpose, for example, within
approximately 2
days. It is believed that mechanical failure is achieved by the first stage,
wherein the
crystalline structure is compromised by hydrolysis. The resultant compromised
material
is a softer, more malleable PGA particulate matter that otherwise retains its
chemical
and mechanical properties.
[62] Over time, the particulate matter enters the second stage and begins
biodegradation proper. The high pressure of fracking on the frac ball against
the seat is
believed to deform the spherical PGA frac ball in its partially amorphous
state and
deteriorating outer surface, by elongating it through the seat and eventually
pushing it
through the seat. The presence of acids may enhance solubility of the frac
ball and
speed degradation. Increasing well bore pressure is believed to speed release
of the
frac ball by increasing fluid temperature and mechanical stress on the ball at
the
ball/seat interface.
[63] Advantageously, PGA frac balls made of Kuredux PGA resin have
strength similar to metals. This allows them to be used for effective
isolation in the
extremely high pressure environment of fracking operations. Once the Kuredux
PGA
resin balls start to degrade, they begin to lose their structural integrity,
and easily
unseat, moving out of the way of hydrocarbon production. Eventually, the balls
degrade
completely.
[64] Kuredux PGA resin or other suitable PGA can also be used to
manufacture other downhole tools that are designed to be used to perform their
similar
14
conventional tool function but, rather than them being removed from the well
bore by
being drilled out instead deteriorate as taught herein. For example, a flapper
valve,
such as is disclosed in U.S. Patent 7,287,596, can be
manufactured with Kuredux, so that it can be left to deteriorate after a zone
has been
fracked. A composite bridge plug can also be manufactured with PGA. This may
obviate the need to mill out the bridge plug after fracking, or may make
milling out the
bridge plug faster and easier. As disclosed herein, such elements will
initially function
as conventional elements; but, after being subjected to downhole fluids of the
pressures
and temperatures disclosed herein will degrade and then disintegrate,
eliminating the
need to mechanically remove them from the well.
[65] Kuredux PGA resin specifically has been disclosed here as an
exemplary material for use in creating degradable PGA frac balls. Furthermore,
while
the PGA balls in this exemplary embodiment are referred to as "PGA frac
balls," those
having skill in the art will recognize that such balls have numerous
applications,
including numerous applications in hydrocarbon recovery. Embodiments disclosed
herein include any spherical ball constructed of substantially of high-
molecular weight
polyglycolic acid which has sufficient compression resistance and structural
integrity to
be used as a frac ball in hydrocarbon recovery operations and which then
degrades and
disintegrates, so it is not necessary to mechanically remove the ball from the
well.
[66] Figs. 2-13 and Figs. 24A and 24B below illustrate downhole tools for well
completion, remediation, abandonment or other suitable uses. Incuded are
downhole
tools for frac applications, including hydraulic fracing. These include tools
for plug and
perf frac applications. The structural members' function will be apparent to
one skilled
in the art. In one embodiment, the tool illustrated may have at least one (and
up to all)
structural members that is non-composite (homogenous), non-metallic, and
degradable.
As used herein, an element is degradable if, when exposed to a downhole fluid
having a
temperature greater than about 150 F, it substantially degrades into
environmentally
harmless substances. Further details regarding degradable materials and
structure
may be found in US 2013/0240201.
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[67] In one embodiment, the one or more degradable structural members are
comprised of polyglycolic acid, including Kuredux 100R60 from Kureha Corp. or
TLF-
6267 polyglycolic acid ("PGA") from DuPont Specialty Chemicals. Additional
suitable
dissolvable materials include polymers and biodegradable polymers, for
example,
polyvinyl-alcohol based polymers such as the polymer HydroceneTM available
from
ldroplax, S.r.l. located in Altopascia, Italy, polylactide ("PLA") polymer
4060D from
Nature-WorksTM, a division of Cargill Dow LC; polycaprolactams and mxitures of
PLA
and PGA; solid acids, such as sulfamic acid, trichloroacetic acid, and citric
acid, held
together with a wax or other suitable binder materials; polyethylene
homopolymers and
paraffin waxes; polyalkylene oxides, such as polyethylene oxides, and
polyalkylene
glycols, such as polyethylene glycols. These polymers may be preferred in
water-based
drilling fluids because they are slowly soluble in water.
[68] In one of the foregoing embodiments, some of the non-degradable
structural elements are comprised of easily milled composites, such as
resin/fiber mixes
known in the art, in another of the following embodiments, where slips,
elastomers, and
springs are disclosed, one or more of these may be non-degradable, and made
from
known, prior art material.
[69] Fig. 2 is a cutaway side view of an exemplary embodiment of a wire line
cement retainer with a poppet valve assembly. This tool has functions apparent
to one
skilled in the art, such as remedial cementing or zone abandonment. The poppet
one-
way check valve may be opened in conjunction with a stinger assembly and
applied
pressure from the surface.
[70] This tool may have one or a plurality of structural members made from a
degradable material, in one case PGAõ which members may include one or more of
the following, whose functions and structure are apparent to those of ordinary
skill in the
art: 1a mandrel: 2a ball drop push sleeve cap; 3a mandrel lock (ratchet) ring;
4a
mandrel lock ring insert; 5a push sleeve; 6a slip; 7a backup cone; 8a end
element
(elastomer); 9a center element (elastomer); 10a shoe nut bottom; 11a 0-ring;
12a ball
bearing; 13a compression spring; 14a bottom nut; 15a bottom sub; 16a socket
head;
17a slip retainer; and 18a socket head.
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[71] In one embodiment, one or more of the structural members are made of
PGA (polyglycolic acid). In another embodiment, the slips are metallic or
other
composition known in the art, center elements 8a and 9a are known non-
degradable
elastomers, and compression spring 13a made of steel or of known prior art
composition. In another embodiment, some of the elements of the plug are
degradable,
including PGA and some of a low metallic composite material, such as a fiber
and resin.
[72] Cement retainer 200 can be set on a wire line or coil tubing used in
conventional setting tools. Upon setting, the stinger assembly is attached to
the work
string and run to retainer depth. The stinger is then inserted into the
retainer bore,
sealing against the mandrel inner diameter, and isolating the work string from
the upper
annulus.
[73] Cement retainer 200 may also, in one embodiment, include PGA slips,
which may be structurally similar to prior art iron slips, which are molded or
machined
PGA according to methods disclosed herein. Teeth may be added to the tips of
the
PGA slips to aid in gripping raw casing and be made of iron, tungsten carbide
or other
hard materials known in the art. In other embodiments (see Figs. 23A-23C), the
PGA
slip may include a PGA based material with hardened buttons of ceramic, iron,
tungsten
carbide or other hard materials embedded therein. Some embodiments of cement
retainer 200 may be configured for use with a PGA or other degradable frac
ball 110.
[74] Once sufficient set down weight has been established, applied pressure
(cement) is pumped down the working string, opening the one-way check valve,
and
allowing communication beneath the cement retainer 200. In some embodiments,
with
PGA elements or other degradable elements as part thereof, cement retainer 200
may
require no drilling whatsoever, the degradable elements simply breaking down
at the
downhole heat and pressure. In some embodiments, the metallic elements
remaining
after the degradable elements degrade may be sufficiently small to pump out of
the
wellbore or drop to the bottom of the well. In other embodiments, minimal
drilling may
be required to clean out the remaining metallic pieces.
[75] Fig. 3 illustrates a wire line cement retainer 300 with a collet 16(b)
for use
in ways known in the art. Cement retainer 300 may have one or more degradable
structural members or PGA structural members, including one or more of the
following:
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funnel 1b, push sleeve 2b, mandrel lock (ratchet) ring 3b, mandrel lock ring
insert 4b,
socket head 5b, slip section 6b, backup cone 7b, end element 8b, center
element 9b,
mandrel 10b, 0-ring lib, bottom nut 12b, 0-ring 13b, collet housing 14b, 0-
ring 15b,
collet 16b, bottom sub 17b, tension spring 18b, socket head 19b, and slip
retainer 20b.
in another embodiment, some of the elements, such as slips, elastomers, and
springs,
may be made of known prior art materials, including non-degradable elastomers
and
metals. In another embodiment, some of the elements of the plug are
degradable,
including PGA and some of a low metallic composite material, such as a fiber
and resin.
[76] Fig. 4 illustrates a cutaway side view of an exemplary embodiment of a
mechanically set retainer 400 with one or more of the following elements
comprising a
degradable material, in one case, PGA: top slip section lc, stinger latch ring
2c, top
cone 3c, socket head 4c, mandrel lock (ratchet) ring 5c, mandrel lock ring
insert 6c, top
backup cone 7c, end element 8c, center element 9c, mandrel 10c, collet 11c,
backup
cone 12c, slip section 13c, slip retainer 14c, lower cap 15c, lower lock ring
16c, 0-ring
17, 0-ring 18c, bottom sub 19c, socket head 20c. in another preferred
embodiment,
one or more elements may be a composite material as known in the art. In
another
embodiment, the slips and elastomers may be made of materials known in the
art.
[77] Fig. 5 is a cutaway side view of an exemplary embodiment of a frac plug
500 that may be comprised of one or more degradable elements including, in one
embodiment, PGA or may be a combination of PGA composite and traditional,
prior art
materials. The PGA (degradable) element may include one or more of the
following:
mandrel Id, load ring 2d, slip section 3d, socket head 4d, backup cone 5d,
backup cone
6d, end element 7d, center element 8d, bottom (standard conical) 9d, sheer sub
10d,
backup spring 11d, torsion spring 12d, socket heads 13d, and slip retainer
14d. Some
of the foregoing elements may be made of traditional materials, such as the
springs,
elastomers, slips. For a ball drop configuration, ball 18d may be degradable
or non-
degradable. For wiper style pumpdown configuration only, bolt 15d, washer lock
16d,
and pumpdown elements 17d may be made of degradable material or conventional
materials.
[78] Fig. 6 is a cutaway side view of an exemplary embodiment of a temporary
isolation tool 600 including, in one embodiment, a ball drop plug that may
have one or
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more of the following elements comprised of a degradable material: push sleeve
le,
socket head 2e, mandrel lock (ratchet) ring for push sleeve 3e, mandrel lock
ring insert
for push sleeve 4e, push sleeve 5e, slip sections 6e, slip retainers 7e,
backup cones 8e,
socket heads 9e, end elements 10e, center element lie, bottom shoe nut 12e,
bottom
nut 13e, torsion spring 14e, 0-ring 15e. Pumpdown element may include aluminum
bolts 16e and pumpdown element 17e. Ball drop may include ball 18e, shear sub
ball
drop plug 19e, and mandrel 20e. In one embodiment, some of the foregoing
elements
are PGA, some are composite, and some conventional materials.
[79] In one embodiment, temporary isolation tool 600 is in a "ball drop"
configuration and the PGA (or a non-degradable) frac ball 18e may be used
therewith.
As known in the art, temporary isolation tool 600 may be combined with three
additional
on-the-fly inserts (a bridge plug, a flow back valve or a flow back valve with
a frac ball,
providing additional versatility). In some embodiments, a pumpdown wiper 17e,
in one
case a degradable material, may be employed to aid in inserting temporary
isolation tool
600 in the horizontal wellbores.
[80] Fig. 7 is a cutaway side view of an exemplary embodiment with a snub
nose plug 700. The degradable elements of the snub nose plug 700 may include
one or
more of the following degradable elements: mandrel if, load ring 2f, slip
sections 3f,
cones 4f set screws 5f, center element 6f, bottom (standard wedge) 7f, shear
sub insert
8f, set screws 9f, slip retainers 10f, tension spring llf, tension spring 12f.
A degradable
PGA wiper 14f may be used to aid inserting snub nose plug 700 into horizontal
wall
bores. Snub nose plug 700 may be provided in several configurations, including
a ball
drop having ball 15f or a bridge plug with insert 16f. Configured as a snub
nose
flowback standard wedge bottom, flowback insert 16f may be used with
ballbearing 17f
and ball 18f for mid-range or high range use.
[81] Fig. 8, in one embodiment, a long range plug 800 is provided having a
number of common components as well as add-ons. Among the common components
of long range plug 800 are the following, at least one of which may be made of
a
degradable (in one case PGA) material: plug collar 1g, thrust rings 2g,
mandrel 3g, load
ring 4g, socket heads 5g, slips 6g, slip retainers 7g, socket heads 8g, cones
9g, backup
cones 10g, backup cones (metallic) 11g, end elements 12g, center element 13g,
shoe
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bottom 14g, torsion spring 15g, body lock ring retainer 16g, mandrel lock
ratchet ring
17g, ratchet load ring retainer 18g. The add-ons may include a dart wiper 19g
or other
suitable wiper, a pumpdown mandrel 20g, and an aluminum bolt 21g.
[82] A ball drop having ball bearing 22g may be added in one embodiment. A
bridge plug insert 23g may be provided as well as the flowback add-ons, ball
bearing
24g, and flowback insert 25g.
[83] Any one or more of the foregoing elements may be PGA or other
degradable material. In one embodiment, long range composite frac plug 800 is
operated according to methods known in the art, enabling wellbore isolation in
a broad
range of environments and applications. Because long range frac plug 800 has a
slim
outer diameter, for example, about 3.9", it may be used with restricted
internal casing
diameters or existing casing patches in a wellbore.
[84] When built with a oneway check valve, long range frac plug 800
temporarily prevents sand from invading the upper zone and eliminates cross-
flow
problems, in some embodiments, by using a degradable frac ball, such as
disclosed
herein. After the frac ball has degraded, fluids in the two zones may co-
mingle. The
operator can then independently treat or test each zone and remove the flow
plugs in an
underbalance environment in one trip. In one embodiment, long range frac plug
800 is
left in the wellbore and the degradable elements, including PGA elements, are
permitted
to breakdown naturally. In some embodiment, the remaining metallic pieces may
be
sufficiently small to pump it out of the wellbore or drop to the bottom of the
well. In other
embodiments, more drilling may be required to clean up remaining metallic
bits.
[85] Fig. 9 is a cutaway side view of an exemplary embodiment of a dual disk
frangible knockout isolation sub 900. In an exemplary embodiment, dual disk
isolation
sub 900 may include a box body 1h, dual housing 2h, degradable disks including
PGA
disks 3h fixedly engaging a support structure comprising the box body and the
dual
housing at a perimeter of the disk, 0-rings such as 90 durometer 0-rings
4h/5h, anti-
extrusion 0-rings such as PTFE 0-rings 6h, and pin body 7h. In one embodiment,
only
the disks are degradable.
[86] In one embodiment, the two dome-shaped disks are a degradable
material, such as PGA. In one embodiment, dual disk isolation sub 900 is under
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bottom of the tubing and/or below a production packer BHA (Bottom Hole
Assembly) .
After the production packer is set with the dual disks, the wellbore reservoir
is isolated.
After the upper production BHA is run in hole, latched into the packer, and
all tests
performed, the disks can be knocked out using a drop bar, coil tubing, slip
line or sand
line or they may be allowed to degrade. Once the disks are gone, the wellbore
fluids
can then be produced up the production tubing. The disks may be dome-shaped as
illustrated or curved or flat. If the disks are broken, the individual
degradable pieces
may then degrade.
[87] Fig. 10 is a cutaway side view of an exemplary embodiment of a single
disk, frangible knockout isolation sub 1000. In one embodiment, single disk
isolation
sub 1000 includes single body housing 1i, pin body 21, a degradable disk 3i
fixedly
engaging a support structure comprising the body housing and pin body at a
perimeter
of the disk, 0-rings 4i/5i, such as 90 durometer 0-rings, and 0-ring 61 such
as a PTFE
anti-extrusion 0-ring. The single PGA disk may be dome-shaped, may be a solid
cylindrical plug or any other suitable shape, including curved or flat.
[88] For both snubbing and pumpout applications, isolation sub 1000 provides
an economical alternative to traditional methods. It is designed to work in a
range of
isolation operations. Isolation sub 1000 may be run to the bottom of the
tubing or below
production packer bottom hole assembly (BHA). Once the production packer is
set,
isolation sub isolates the wellbore reservoir.
[89] After the upper production bottom hole assembly is run in the hole,
latched
into the packer, and all tests are performed, degradable disk 31 may be pumped
out. In
other embodiments, a PGA disk can simply be allowed to disintegrate. Once the
disk is
removed or disintegrates, then wellbore fluids can be produced up the
production
tubing.
[90] Fig. 11 is a cutaway side view of an exemplary embodiment of an
underbalance disk sub assembly 1100, which may in one embodiment include a
single
housing 1j, and an underbalance pin body 2j. A degradable disk, including in
one
embodiment, a PGA disk 3j may be provided for fixedly engaging a support
structure
comprising the single housing and the pin body at a perimeter of the disk. 0-
rings 4j/5j
may be provided, such as 90 durometer 0-rings, as well as anti-extrusion PTFE
0-rings
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6j. in one embodiment, only the disk is degradable or PGA. Underbalance disk
sub
1100 may be part of a casing string and production ports may be provided as
seen in
pin body 2j, which provides a hydrocarbon circulation. A single disk 3j may be
provided
for zonal isolation. Isolation sub 1100 is operated according to methods known
in the
art.
[91] Fig. 12 is a cutaway side view of an exemplary embodiment of an isolation
sub assembly 1200, which may include the following elements: coated box body
1k,
backup rings 2k, 0-rings 3k/4k, such as 90 durometer 0-rings, PGA disk 5k,
housing
6k, and pin body 7k. Degradable disk 5k fixedly engages a support structure
comprising the box body and housing at a perimeter of the disk.
[92] Isolation sub assembly 1200 may have a single PGA or other degradable
disk 5k that may be either broken in ways known in the art or allowed to
dissolve at the
downhole temperature and pressures in ways set forth herein at predetermined
times to
permit fluid communication through the isolation sub.
[931 Figs. 13 - 130 are detailed views of an exemplary isolation sub 1320. In
Fig. 13, an exemplary embodiment, isolation sub 1300 is operated according to
methods known in the prior art. Fig. 13 provides a partial cutaway view of
isolation sub
1300 including a metal casing 1310. Casing 1310 is configured to interface
with the
tubing or casing string, including via female interface 1314 and male
interface 1312,
which permit isolation sub 1300 to threadingly engage other portions of the
tubing or
casing string. Disposed along the circumference of casing 1310 is a plurality
of ports
1320. In operation, ports 1320 are initially plugged with a retaining plug
1350 during the
fracking operation, but ports 1320 are configured to open so that hydrocarbons
can
circulate through ports 1350 once production begins. Retaining plug 1350 is
sealed
with a 0-ring 1340 and threadingly engages a port void 1380 (Fig. 13A). Sealed
within
retaining plug 1350 is a degradable PGA plug 1360, sealed in part by plug 0-
rings 1370.
[94] Fig. 13A is a cutaway side view of isolation sub. Shown particularly in
this
figure are bisecting lines A-A and B-B. Disposed around the circumference of
casing
1310 are pluralities of port voids 1380, which fluidly communicate with the
interior of
casing 1310. Port voids 1380 are configured to threadingly receive retaining
plugs
1350. A detail of port void 1380 is also included in this figure. As seen in
sections A-A
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and B-B, two courses of port voids 1380 are included. The first course,
including port
voids 1380-1, 1380-2, 1380-3, and 1380-4 are disposed at substantially equal
distances
around the circumference of casing 1310. The second course, including port
voids
1380-5, 1380-6, 1380-7, and 1380-8 are also disposed at substantially equal
distances
around the circumference of casing 1310 and are offset from the first course
by
approximately forty-five degrees.
[95] Fig. 13B contains a more detailed side view of PGA plug 1360. In an
exemplary embodiment, PGA plug 1360 is made of machined, solid-state high-
molecular weight polyglycolic acid. The total circumference of degradable plug
1360
may be approximately 0.490 inches or in the range of conventional plugs. Two 0-
ring
grooves 1362 may be included, with an exemplary width between about 0.093 and
0.098 inches each, and an exemplary depth of approximately 0.1 inches.
[96] Fig. 13C contains a more detailed side view of a retaining plug 1350.
Retaining plug 1350 includes a screw or hex head 1354 to aid in mechanical
insertion of
retaining plug 1350 into port void 1380 (Fig. 13A). Retaining plug 1350 also
includes
threading 1356, which permits retaining plug 1350 to threadingly engage port
void 1380.
An 0-ring groove 1352 may be included to enable plug aperture 1358 to securely
seal
into port void 1380. A plug aperture 1358 is also included to securely and
snugly
receive a PGA or other degradable plug 1360. In operation, isolation sub 1300
is
installed in a well casing or tubing. After the fracking operation is
complete, degradable
plugs 1360 will break down in the pressure and temperature environment of the
well,
opening ports 1320. This will enable hydrocarbons to circulate through ports
1320.
[97] FIG. 14 is a side view of an exemplary embodiment of a pumpdown dart
1400. In an exemplary embodiment, pumpdown dart 1400 is operated according to
methods known in the prior art. In particular, pumpdown dart 1400 may be used
in
horizontal drilling applications to properly insert tools that may otherwise
not properly
proceed through the casing. Pumpdown dart 1400 includes a PGA (or other
degradable) dart body 1410, which is a semi-rigid body configured to fit
tightly within the
casing. In some embodiments, a threaded post 1420 is also provided, which
optionally
may also be made of PGA material. Some applications for threaded post 1420 are
known in the art. In some embodiments, threaded post 1420 may also be
configured to
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interface with a threaded frac ball 1430. Pumpdown dart 1400 may be used
particularly
in horizontal drilling operations to ensure that threaded frac ball 1430 does
not snag or
otherwise become obstructed, so that it can ultimately properly set in a valve
seat.
[98] Advantageously, pumpdown dart 1400 permits threaded frac ball 1430 to
be seated with substantially less pressure and fluid than is required to seat
PGA frac
ball 110.
[99] The following relates to tests performed on degradable balls. The
specific
gravity of the balls tested was about 1.50. They were machined to tolerances
held at
about .005 inches. Kuredux PGA balls were field tested at a pump rate of 20
barrels
per minute and exhibited high compressive strength, but relatively fast break
down into
environmentally friendly products.
[100] Fig. 15 illustrates the ball degradation rate of a 3 inch OD PGA frac
ball
versus time at 275 F, the PGA ball made from 100 R60 Kuredux PGA resin
according
to the teachings set forth herein. The 3 inch ball is set on a 2.2 inch ball
seat ID and
passes the ball seat at about 12 or 13 hours. Degradation rate about .033
inches/hour.
[101] Fig. 16 illustrates the reduction in ball diameter versus temperature.
Reduction in ball diameter increases as temperature increases. A noticeable
reduction
in diameter is first apparent at about 125 F. More significant reduction in
diameter
begins at 175-200 F.
[102] Fig. 17 shows a pressure integrity versus diameter curve illustrating
pressure integrity of PGA frac balls for various ball diameters. It
illustrates the structural
integrity, that is, the strength of Kuredux PGA resin balls beginning with a
ball
diameter of about 1.5 inches and increasing to about 5 inches as tested on
seats which
are each 1/8-inch smaller than each tested ball. The pressure testing protocol
is
illustrated in the examples below. The tests were performed in water at
ambient
temperature.
FRAC BALL EXAMPLE 1
[103] A first test was performed with a 3.375 inch frac ball. Pressurizing was
begun. Pressure was increased until, upon reaching 6633 psi, the pressure
dropped to
around 1000 psi. Continued to increase pressure. The ball passed through the
seat at
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1401 psi. The 3.375 inch frac ball broke into several pieces after passing
through the
seat and slamming into the other side of the test apparatus.
FRAC BALL EXAMPLE 2
[104] A second test was performed with a 2.125 inch frac ball. Pressurizing
was
begun. Upon reaching 10,000 psi, that pressure was held for 15 minutes. After
the 15
minute hold, pressure was increased to take the frac ball to failure. At
14,189 psi, the
pressure dropped to 13,304 psi. Pressure increase continued until the ball
passed
through the seat at 14,182 psi.
FRAC BALL EXAMPLE 3
[105] A third test was performed with a 1.500 inch frac ball. Pressurizing was
begun. Upon reaching 10,000 psi, that pressure was held for 15 minutes. After
the 15
minute hold, pressure was increased to 14,500 psi and held for 5 minutes. All
pressure
was then bled off. The test did not take this ball to failure. Removing the
ball from the
seat took very little effort, it was removed by hand. Close examination of the
frac ball
revealed barely perceptible indentation where it had been seated on the ball
seat.
[106] In one preferred embodiment, Applicant's PGA ball operates downhole
from formation pressure and temperature to fracking pressures up to 15,000 psi
and
temperatures up to 400 F.
FRAC BALL PRESSURE TESTING WEIGHT LOSS
[107] After pressure testing, two different pieces of the 3 3/8 inch frac ball
were
put into water and heated to try to degrade the pieces. The first piece
weighed 140
grams. It was put into 150 F water. After four days, the first piece weighed
120 grams.
[108] The second piece weighed 160 grams. It was placed in 200 F water.
After four days, the second piece weighed 130 grams.
[109] Fig. 18 illustrates pressure versus time test of a 2.25 inch PGA
Kuredux0
PGA resin ball at 200 F and pressures up to 8000 indicating the period of time
in
minutes that the pressure was held. Psi at top and psi on bottom are both
shown. The
ball held at pressures between 8000 and about 5000 psi up to about 400
minutes. The
test was run using a Maximater Pneumatic plunger-type, in a fresh water heat
bath.
The ball was placed in a specially designed ball seat housing at set
temperature to
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200 F. Pressure on the top side of the ball was increased at 2000 psi
increments, each
isolated and monitored for a 5 minute duration. Pressure was then increased on
top
side of the ball to 4000 psi, isolated and monitored for a 5 minute duration.
Pressure
was increased on the top side of the ball to 8000 psi, isolated and monitored
until
failure. The assembly was then bled down. There was no sign of fluid bypass
throughout the duration of the hold. The top side pressure decrease see in
Fig. 18 was
probably caused by the ball beginning to deteriorate and slide into the ball
seat. Due to
the minimal fluid volume above the ball in the test apparatus, pressure loss
caused by
this is evident. In contrast, a well bore has relatively infinite volume
versus likely ball
deformation. After 6 plus hours of holding pressure without failing, top side
pressure
was bled down and the test completed. The ball was examined upon removal from
the
ball seat. It had begun to deform and begun to take a more cylindrical shape,
like the
ball seat fixture. While it was intended to take the ball to failure, the
testing was
substantially complete after 6 hours at 5000+ psi.
(110.1 in the absence of fluid flow adjacent the ball, the ball's temperature
will be
substantially determined by the temperature of the formation of the zone where
the ball
is seated. An increase in pressure upon the ball due to fracking may produce
an
increase in adjacent downhole temperature, and, in addition to other factors,
such as
how far removed the ball is from the fracking ports, increase downhole fluid
temperature
adjacent the ball. For example, increasing downhole pressure to 10,000 psi may
produce a downhole fluid temperature of 350 F and increasing downhole
pressure to
15,000 psi may produce a 400 F temperature. Because degradation is
temperature
dependent, higher temperatures will cause degradation to begin more quickly
and for
the degradable element to fail more quickly. Duration from initiation of
fracking until the
PGA frac ball fails will generally decrease with increasing temperature and
pressure.
Accordingly, for a given desired blockage duration, other conditions being
equal,
desired PGA frac ball diameters increase with increasing pressure and with
increasing
temperature.
[111] Fluid flow of fluid from the surface adjacent to the ball typically
cools the
ball. Accordingly, it is believed flowing fracking fluid close to the ball,
cools the ball.
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These are factors which the operator may consider in determining preferable
ball/seat
overlap and ball size for the particular operation.
[112] Taking these factors into account in choice of frac ball size, PGA frac
balls
for example, are useful for pressures and temperatures up to at least 15,000
pi and 400
F, it being understood that pressure and temperature effects are inversely
related to
the duration of time the PGA frac ball must be exposed to the downhole fluid
environment before it is sufficiently malleable and sufficiently deteriorated
to pass
through the seat. It is believed the PGA frac ball undergoes a change from a
hard
crystalline material to a more malleable amorphous material, which amorphous
material
degrades or deteriorates, causing the ball to lose mass. These processes
operate from
the ball's outer surface inward. The increasing pressure of fracking increases
downhole
fluid temperature and causes shearing stress on the conical portion of the
ball abutting
the seat. It is believed as these several processes progress, they cooperate
to squeeze
the shrinking, more malleable ball which is under greater shear stress through
the seat.
It is believed the described downhole tools comprised of the described
materials will
initially function as conventional downhole tools and then deteriorate as
described
herein. It is believed that the described several processes function together
to
accomplish the change from the initial hard dense frac ball blocking the well
bore by
sealing against the seat to the more malleable less dense frac ball which has
passed
through the seat, unblocking the well bore. At greater pressure and
temperatures,
deterioration occurs at a more rapid rate. Degradation produced by higher
pressure
and higher temperature for a shorter time is believed to be accomplished by
processes
which are similar to degradation produced at a lower pressure and lower
temperature
for a longer time. These are deterministic processes which produce reliably
repetitive
and predictable results from similar conditions. Knowledge of these processes
can be
used to calculate the duration for different size frac balls will pass through
the seat of a
plug at a particular depth, pressure and temperature. This permits the
operator to select
a ball, which will seal the wellbore by blocking the plug for the operators
chosen
duration. This is advantageous in field operations because it permits
production
operations to be tightly and reliably scheduled and accomplished.
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[113] The size of the ball relative to the seat is selected to produce the
desired
bridge plug conduit blockage duration for the particular well situation in
light of the
conditions where the subject bridge plug will be positioned. The lower the
temperature
of the formation at the location where the where the bridge plug will be used,
the smaller
the preferred size of the ball relative to the seat for a given desired
duration of bridge
plug conduit blockage. The higher the temperature of the formation where the
bridge
plug will be used, the larger the preferred size of the ball relative to the
seat for a given
desired duration of bridge plug conduit blockage. Likewise, the longer the
period of time
desired for the ball to block the conduit by remaining on the seat, the larger
the
preferred size of the ball relative to the seat for a given desired duration
of bridge plug
conduit blockage. The shorter the period of time desired for the ball to block
conduit by
remaining on the seat, the smaller the preferred size of the ball relative to
the seat for a
given desired duration of bridge plug conduit blockage.
[114] Fig. 15 illustrates the ball degradation rate of a 3 inch OD PGA frac
ball
versus time at 275 F, the PGA ball made from 100 R60 Kureduxe PGA resin
aceurditly
to the teachings set forth herein. Figure 16 shows a graph of the ball
diameter
degradation rate (in/hr) versus temperature relationship which illustrates
that the rate of
ball diameter degradation increases as temperature increases. FIGS. 17 and 17
A
illustrate integrity v. diameter test results for applicant's PGA balls when
subjected to
pressures between 3000 to 15,000 pounds, for ball overlaps of 1/8 inches and
14
inches. Use of the relationships shown in Figures 15, 16, and 17 with known
formation
conditions where the bridge plug will be positioned, seat size and desired
duration of
bridge plug conduit blockage produces a desired ball diameter for the
particular
formation location and task. For a given bridge plug conduit blockage duration
and seat
size, a greater formation temperature produces a larger desired ball diameter.
For
example, for a given bridge plug conduit blockage duration and seat size, the
ball
diameter will be larger for a 300 F formation location than for a 225
formation location.
The relationship of such conditions, relative ball and seat sizes and blockage
times is
taught by the disclosures herein.
[115] Applicant's balls and methods of using them in downhole isolation
operations comprise providing a set of balls to an operator which set has
balls of
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predetermined and predefined sizes. An exemplary set of balls comprises balls
within
the range of 1.313 inches to 3.500 inches, which balls provide the operator
with
predefined and predetermined size differences, either uniform size differences
or
nonuniform size differences. For example, the size differences may be 1/16
inch or 1/4
inch between each ball size. For example, for an exemplary useful set of balls
may
comprise balls sized 1.313; 1.813; 1.875; 1.938; 2.000; 2.500; 2.750; 2.813;
2.938;
3.188; 3.250; and 3.500.
[116] Applicant's method of choosing an appropriate ball size for use with a
particular isolation tool to be used at a particular depth in a particular
well includes use
of the decision tree disclosed herein, which decision tree for a particular
operation may
include consideration of some of times, pressures, temperatures, clearance
through
higher isolation tools with seats, and the size of the particular isolation
tool's seat to
determine the desired ball/seat overlap, and thus the appropriate ball size.
Times may
include time of the ball on the seat, fracking time, time for the ball to pass
through the
seat, time to substantial ball deterioration and time for substantially total
ball
disintegration into non-toxic byproducts. Pressures may include pressure on
the ball at
the particular isolation tool prior to fracking, pressure on the ball during
fracking, and
pressure on the ball after fracking. Temperatures may include temperature at
the
particular isolation tool prior to fracking, temperature at the ball during
fracking, and
temperature at the ball after fracking. Required clearance through the seats
of higher
isolation tools and consideration of the number of seats through which the
ball will
pass before reaching the target seat on the target isolation tool. Preferably
at least
about 0.4 inches of clearance will be provided between the ball and the higher
seat
through which the ball must pass before reaching the target seat. The size of
the target
seat determines the size of the ball to provide the desired ball/seat overlap,
which
Applicant's decision tree determines is most preferable for the particular
operation. The
data of FIGS. 15, 16, 17 and 17 A are used in Applicant's method of
determining the
appropriate ball size for the particular operation.
[117] Applicant's preferred apparatus and method includes providing an
appropriate set of balls to the operator at the well site prior to the
operator needing the
balls for the operation. The balls in the set of balls have predefined and
predetermined
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sizes selected to be appropriate for the operator's needs at the specific
well. Although
different arbitrary sizes of balls can be provided, Applicant's method
includes providing
the operator with balls which have a uniform size difference between the balls
and
which size difference is chosen to most likely provide ball sizes appropriate
for the
operator's needs.
[118] In a previous example, Kuredux PGA frac balls are provided in sizes
between 0.75 inches and 4.625 inches, to facilitate operation of frac sleeves
of various
sizes. In other embodiments, balls may be provided in increments from about 1
inch up
to over about 7 inches. It is advantageous to provide to the operator a set of
balls which
have uniform incremental sizes, to ensure the operator has on hand balls
appropriate to
the operator's immediate needs and preferences. In some applications, ball
sizes in the
delivered set are preferably increased in one-eighth inch increments. In
other
applications, the incremental increase in ball sizes in the delivered set is
preferably in
sixteenths of an inch. Thus, in appropriate cases, a set of balls is delivered
to the
operator appropriate for fracking the desired zones with a single run of frac
balls which
are immediately available to the operator due to having been previously
provided the
operator in a predetermined set of frac balls. It is typical for an operator
to frac more
than 12 and less than 25 zones with a single run of frac balls. A set of PGA
frac balls
delivered to a well site may comprise between 10 and 50 frac balls. A
preferable set of
PGA frac balls delivered to a well site may comprise 12 to 25 frac balls. If
the operator
has on hand an appropriate set of frac balls, the operator may frac up to 63
zones with
a single run of frac balls.
[119] Other conditions and measurements being equal, smaller balls can resist
more pressure for longer than larger balls having the same ball/seat overlap.
In some
embodiments, the overlap or difference between seat diameter and ball diameter
may
be about 1/8 inch or about % inch. In one embodiment, the balls at or over 3"
in
diameter have about 1/4 inch smaller seats, and those under 3" in diameter
have about
1/8 inch difference. If a time longer than about 10-15 hours until frac
completion and/or
downhole temperature conditions exceed about 275 , then ball diameters, and
overlap
of the ball over the seat, may be increased accordingly to increase the
duration of the
ball on the seat.
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[120] The operator, being aware of depths and formation conditions at each of
the isolation plug locations in the wellbore, and deciding upon how many
isolation plugs
are to be used to produce the well, determines desired ball sizes and seats
for each of
the isolation plugs to be used in the well from the balls available in the set
of balls at the
well site using the methods described herein. Upon determining desired ball
sizes for
the several isolation plugs from the immediately available set of preselected
and
predetermined balls, the operator uses the disclosed decision tree factors to
determine
the appropriate ball for each isolation plug from the preselected appropriate
set of balls,
and uses each chosen ball for its target seat in its target isolation valve in
the fracking or
other isolation tool operation at each target formation location. This method
of having a
pre-delivered set of balls appropriate for the well at the well site, and
method for
selecting appropriate balls from the pre-delivered set of balls provides the
operator with
a convenient, timely and efficient method for having appropriate balls
immediately
available, determining ball sizes appropriate for production operations at the
well,
selecting appropriate balls from the set of bails, and using them in the
production
operation at the well.
[121] In some embodiments of some isolation valves, such as a frac sleeve,
multiple balls are used with the isolation tool. For example, some tools
require four frac
balls to operate a frac sleeve. In those cases, a plurality of identically
sized PGA frac
balls, 110 are provided and available and are used.
[122] Fig. 19 illustrates a structural diagram of a 51/2 inch snub nose ball
drop
valve with the item numbers listed as item number 1 to 15 for this Figure
only.
1/2 INCH SNUB NOSE STRUCTURAL INTEGRITY TEST
[123] A 5-% inch snub nose was tested in a 48 inch length tubing. The test
used a single pack-off element with bottom shear at about 32,000 lbs. The PGA
elements of this tool were: mandrel part 1, load ring part 2, cones part 4,
and bottom
part 7 (7a and 7b), the part numbers being as identified on Fig. 19 and being
used for
Fig. 19 only. A Maximater Pneumatic plunger-type pump was used with fresh
water in a
Magnum heat bath. Plug set and tested at ambient temperature. The plug was set
in a
casing (Fig. 19A), and drop ball and pressure increased at top side to 5000
psi to
ensure no leaks. Pressure was increased at top side to 6000 psi, isolated and
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monitored for 15 minutes. Pressure increased at top side to 8000 psi, isolated
and
monitored for 15 minutes. Pressure increased at top side to 10,000 psi,
isolated and
monitored for 20 minute duration (Fig. 19B). Bleed assembly pressure, all
testing
completed. The top slip engagement was 835.9 psi/6018 lbs. The bottom slip
engagement was 1127 psi/8118 lbs. The plug shear, 4370 psi/31,469 lbs.
[124] Once the plug was assembled and installed on the setting tube, it was
lowered into the 5.5 inch, 20 lb. casing. The setting process then began. The
plug was
successfully set with a 31.5 K shear. A ball was dropped onto the mandrel and
the
casing was pumped into the test console. Top side pressure was then increased
to
5000 psi momentarily to check for leaks, either from the test fixture or the
pressure
lines. No leaks were evident and the top side pressure was then increased to
6500 psi
for 15 minute duration. Pressure was then increased top side to 8000 psi for
15 minute
duration. Upon completion of the 8000 psi hold, pressure was increased top
side
10,000 psi for a 20 minute duration. Minimal pressure loss was evident on the
top side
of the plug. This is attributed to additional pack-off and mandrel stroke due
to the fact
that no sign of fluid bypass was evident on the bottom side of the plug. Total
fluid
capacity of the casing was less than 2.5 USG, pressure loss evident top side
at the plug
totaled less than 1 cup. Assembly pressure was then bled down and testing was
completed.
[125] Upon removal of the test cap, there was no sign of eminent failure. The
slips had broken apart perfectly and were fully engaged with the casing wall.
There was
also no sign of element extrusion or mandrel collapse. Everything performed as
designed. Similar testing was done on a 41/4 inch plug with similar results.
[126] Set forth in Figs. 1-14 and 19 above are various embodiments of down
hole tools. In some embodiments of the above described plugs and in the ball
drop
bridge plug and snub nose bridge plug, there are at least the following
elements: a
mandrel, a cone, a top and bottom load ring, and a mule shoe or other
structural
equivalents, of which one or more of such structures may be made from the PGA
or
equivalent polymer disclosed herein. Other elements of the plugs typically not
made
from PGA, and made at least in part according to the teachings of the prior
art are:
elastomer elements, slips, and shear pins. Some prior art downhole tools, not
made of
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PGA, must be milled out after use. This can cost time and can be expensive.
For
example, using PGA or its equivalent in the non-ball and, in some embodiments,
non-
seat, structural elements of the plugs, in addition to using a PGA ball if
applicable or
desired, results in the ability to substantially forego milling out the plug
after it is used.
Due in part to PGA disintegration according to the teachings set forth herein,
at the
described time/temperature conditions, as well as in still fluid down hole
conditions
(substantially non-flow conditions), Applicant has achieved certain
advantages,
including functionally useful, relatively quick, degradability/ disintegration
of these PGA
elements in approximately the same time, temperature, and fluid environmental
conditions of Applicant's novel frac ball as set forth herein.
[127] In one preferred embodiment of the down hole tool structural elements
made from PGA substantially degrade to release the slips from the slip's set
position in
a temperature range of about 136 to about 334 F in between one to twelve
hours, in a
substantially non-fluid flow condition. The fluid may be partially or
substantially
aqueous, may be brine, may be basic or neutral, and may be at ambient pressure
or
pressures. Maximum pressure varies according to the structural requirements of
the
PGA element as shown by the pressure limitation curve of Fig. 17 and as can be
inferred by its teaching.
[128] Some prior art degradable downhole tool elements, upon dissolution,
leave behind incrementally unfriendly materials, some in part due to the
fluids used to
degrade the prior art elements.
[129] In downhole use of downhole tool elements comprised of PGA as
described herein, the PGA elements initially accomplish the functions of
conventional
non-PGA elements and then the PGA elements degraded or disintegrated into non-
toxic
to humans and environmentally-friendly byproducts as described herein.
[130] As set forth herein, when the above described downhole tool elements or
other downhole tool elements comprised of PGA and its equivalents are placed
within
the above conditions, they will typically first perform their conventional
downhole tool
element function and then undergo a first breakdown. This first breakdown
loosens and
ultimately releases the non-PGA elements of the plug from the PGA elements of
the
plug. This includes release of the slips which press against the inner walls
of the
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production tubing to hold the downhole tool in place. Release of the slips
permits
displacement of down hole tool through the well bore. Typically, continued
downhole
degradation then results in substantial breakdown of the PGA elements into
materials
which are non-toxic to humans and environmentally friendly compounds. For
example,
in typical down hole completion and production environments, and the fluids
found
therein. PGA will break down into glycerin, CO2 and water. These are non-toxic
to
humans and environmentally friendly. The slips are usually cast iron, shear
pins usually
brass, and the elastomer usually rubber. However, they may be comprised of any
other
suitable substances. These elements are constructed structurally and of
materials
known in the prior art.
[131] Some prior art downhole tool elements must be mechanically removed
from the well bore, such as by milling them out or retrieving them. The
described PGA
element does not need to be mechanically removed. Some prior art downhole tool
elements require a turbulent flow of fluid upon them for them to degrade or
deteriorate.
The described PGA elements degrade or deteriorate in the prrioe -------- of
tIii downhole
fluid. The described PGA elements primarily only require the presence of a
heated fluid
to begin deteriorating. This is a substantial advantage for PGA-comprised
downhole
tool elements.
[132] Some prior art degradable downhole tool elements require a high or low
PH fluid or require a solvent other than typical downhole fluid to promote
degrading.
The described PGA elements degrade or deteriorate in the presence of typical
hot
downhole fluid and without the necessity of a high or low PH fluid or a
solvent other than
typical hot downhole production fluid. Fluids the described GPA material
degrades in
include hydrocarbons, water, liquid gas, or brine. In one embodiment, no other
substances, for example, metals or ceramics, are mixed with the PGA in the
element.
PGA has been found to degrade in non-acidic oil, liquid gas, brine or any
typical down
hole fluid without needing a significant turbulent flow of the down hole fluid
in the
proximity of the structure element to begin the disintegration. It is
especially useful that
acidic fluids are not necessary for its disintegration.
[133] This is advantageous because some prior art elements are primarily only
quickly dissoluble down hole in the presence of a substantial flow of down
hole fluid or
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in the presence of acidic fluids, conditions which require use of coiled
tubing or other
tool and activity to create conditions for degrading their elements. The
disclosed
embodiment is advantageously used to perform its mechanical functions and then
degrade without further investment of time, tools or activity.
[134] The PGA downhole elements described herein are advantageously stable
at ambient temperature and substantially stable in downhole fluid at downhole
fluid
temperatures of up to about 136 F. PGA downhole elements begin to degrade or
deteriorate in downhole fluid at downhole temperatures of above 136 F, and
preferably
in the range of from 150 F to 300 F. Fracking operations pressurize the
downhole fluid,
and the higher pressures cause higher temperatures. Thus, the PGA element has
the
strength and incompressibility to be used as a conventional downhole tool
element in
the high pressure of fracking operation, and the high pressure of fracking
causes the
downhole fluid temperature to rise, which high downhole fluid temperature
initiates
degradation of the PGA element which allows production of the well without
drilling out
or retrieving the tool.
[135] The predictable duration of time between PGA elements being immersed
in the drilling fluid and the elements degrading is a useful function of the
described
element. The described PGA elements sufficiently degrade or deteriorate after
their
fracking function is completed so they fail their convention tool element
function and
production can proceed without being impeded by the elements remaining in the
bore
hole within about five hours to about two days. For example, a preferred time
for PGA
frac balls to fail by passing through their ball seat is from between about
five to six hours
to about two days. The time to failure is determinable from the teachings
herein and
experience.
[136] In one aspect, a machinable, high molecular weight hydrocarbon polymer
of compressive strength between about 50 and 200 MPa (INSRON 55R-4206,
compression rate 1 mm 1 min, PGA 10x10x4(mm), 73 F to 120 F) may be used as
the
precursor or substrate material from which to make or prepare plug balls,
mandrels,
cones, load rings, and mule shoes or any of those parts degradable in typical
downhole
fluids in high pressure and temperature conditions. In another aspect, one or
more of
such elements of a downhole plug will decay faster than typical metallic such
elements,
typically within several days after being placed within the downhole
environment. In a
more specific aspect, the polyglycolic acid as found in US Patent No.
6,951,956, may be
the polymer or co-polymer and used as the substrate material, and may include
a heat
stabilizer as set forth therein. Polyglycolic acid and its properties may have
the
chemical and physical properties as set forth in the Kuredux Polyglycolic
Acid
Technical Guidebook as of April 20, 2012, and the Kuredux PGA Technical
Information (Compressive Stress) dated January 10, 2012, from Kureha
Corporation,
PGA Research Laboratories, a 34-page document. Both the foregoing Kureha
patent
and the Kuredux technical publications.
Kuredux PGA resin is certified to be a biodegradable plastic in the United
States by
the Biodegradable Plastics Institute and is a fully compostable material
satisfying the
ISO 14855 test protocol.
[137] In a preferred embodiment, Applicant prepares the structural elements of
downhole isolation tools comprising, without limit, the mandrel, load rings,
cones, and
mule shoes from Kuredux 100R60 PGA resin. This is a high density polymer with
a
specific gravity of about 1.50 grams per cubic centimeter in an amorphous
state and
about 1.70 grams per cubic centimeter in a crystalline state, and a maximum
degree of
crystallinity of about 50%. In a preferred embodiment, the Kuredux is used in
pellet
form as a precursor in a manufacturing process, which includes the steps of
extruding
the pellets under heat and pressure into a cylindrical or rectangular bar
stock and
machining the bar stock as set forth herein. In one embodiment of a
manufacturing
method for the structural elements that use the polymer and, more
specifically, the PGA
as set forth herein, extruded stock is cylindrically shaped and used in a
lathe to
generate one or more of the structural elements set forth herein.
[138] The lathe may be set up with and use inserts of the same type as used to
machine aluminum plug elements or downhole parts that are known in the art.
The
lathe may be set up to run and run to a depth of about .250 inches. The lathe
may be
set to run and run at an IPR of .020 inches (typically, 10-70% greater than
used for
aluminum), during the roughing process. The roughing process may run the PGA
stock
dry (no coolant) in one embodiment and at a spindle speed (rpm) and a feed
rate that
are adjusted to knock the particles into a size that resembles parmesan
cheese. This
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will help avoid heat buildup during machining of the structural elements as
disclosed
herein.
[139] In a finishing process, the IPR may be significantly reduced, in one
method, to about .006 inches, and the spindle speed can be increased and the
feed rate
decreased.
[140] In one or more aspects of this invention, the structural elements of the
plug and the ball are made from a homogenous, non-composite (a non-mixture)
body
configured as known in the art to achieve the functions of a ball in one
embodiment, a
mandrel in another, support rings in another, and a mule shoe in another. This
homogenous, non-composite body may be a high molecular weight polymer and may
be configured to degrade in down hole fluids between a temperature of about
136 F
and about 334 F. It may also be adapted to be used with slip seals, elastomer
elements, and shear pins, as structurally and functionally found in the prior
art, and
made from materials found in the prior art.
[141] in certain aspects of Applicant's devices, the homogenous, non-composite
polymer body will be stable at ambient temperatures and, at temperatures of at
least
about 200 F and above, will at least partially degrade to a subsequent
configuration that
unblocks a down hole conduit and will further subsequently degrade into
products
harmless to the environment.
[142] PGA is typically a substantial component of these structural elements
and,
in one embodiment, homogenous. Generally, it has tensile strength similar
to
aluminum, melts from the outside in, is non-porous, and has the crystalline-
like
properties of incompressibility. Although this disclosure uses specific PGA
material and
specific structural examples, it teaches use of materials other than PGA
materials which
degrade or deteriorate in similar downhole conditions or conditions outside
the particular
range of PGA. It further teaches that downhole tools of various structures,
functions,
and compositions, whether homogeneous or heterogeneous, may be usefully used
within the scope of the disclosure to obtain the described useful results.
[143] In one embodiment, heat stabilizers are added to the PGA or other
substrate material to vary the range of temperatures and range of durations of
the
downhole tool element's described functions. Greater downhole depths and
fracking
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pressures produce greater downhole fluid temperatures. An operator may choose
to
use the described degradable elements, modified to not begin degrading as
quickly or
at as low a temperature as described herein. Addition of a heat stabilizer to
the PGA or
other substrate material will produce this desired result.
[144] Although some of the described embodiments are homogenous (non-
composite), the downhole elements may be heterogeneous. Fine or course
particles of
other materials can be included in a substrate admixture. Such particles may
either
degrade more quickly or more slowly than the PGA or other substrate material
to speed
or slow deterioration of the downhole elements as may be appropriate for
different
downhole conditions and tasks. For example, inclusion of higher melting point
non-
degradable material in a PGA ball is expected to delay the ball's passage
through the
seat and delay the ball's deterioration. For example, inclusion of a heat
stabilizer in a
PGA ball is expected to delay the ball's passage through the seat and delay
the ball's
deterioration. For example, inclusion of materials which degrade at
temperatures lower
than temperatures at which PGA degrades or which degrade more quickly than PGA
degrades is expected to speed a ball's passage through the seat and speed a
ball's
deterioration. These teachings are applicable to the other downhole
elements
described herein and to other downhole tools generally.
[145] The predictable duration of time from the temperature initiated
deterioration beginning to degrade the element sufficiently that it fails,
cases to perform
its conventional tool function, under given conditions as taught herein is
advantageous
in field operations. The degradable element's composition, shape, and size can
be
varied to obtain a reliable desired duration of time from temperature-
initiated
deterioration to tool failure. In an embodiment, there are one or more
coatings on the
element, for example, latex paint. These coatings may be used to predictably
extend
the time to the element's malleability and functional dissolution.
(146] As seen in Fig. 20, an exemplary extended reach lateral well may have
about 4-12,000 feet or more of lateral reach between the heel and toe. It may
have a
total vertical depth of about 13-19,000 feet or more. Such an exemplary well
may have
a total measured depth ("TMD") of between about 15,000 and 23,000 feet or
more. Fig.
20 illustrates an extended reach lateral well that may use any of the
embodiments of
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devices and inventions set forth herein, in one case, frac plugs to isolate
hydrocarbon
formations in multi-stage frac operations in horizontal wells.
[147] It is well known to use one type of isolation plug and one type of
isolation
plug removal process to bring a well into production. Extended reach wells
present
additional considerations. Coil tubing may be used to set or drill out
conventional plugs
("Cp'') (that is, plugs with non-degradable elements) up to about 19,000' TMD,
with
increasing difficulty and expense beyond about 15,000'. Drilling out plugs
with coiled
tubing near the toe may be difficult in extended reach applications. A
different method
is: (1) using conventional plugs through about 15,000' to 19,000' and drilling
out those
conventional plugs, and (2) using plugs with degradable elements as set forth
herein
beyond about 15,000', typically out to about 19,000' and leaving the plugs
with
degradable elements to degrade is a beneficial and cost effective method for
bringing a
well into production.
[148] A method is provided for (1) setting, using and drilling out
conventional
plugs from the surface through about 15,000, typically out to about 19,000
feet, and (2)
setting, and using (for fracing in one instance) plugs with degradable
elements,
including, for example, elements made of PGA, from about 15,000 to 19,000 feet
and
up to the toe, and leaving the plugs with degradable elements to degrade,
rather than
drilling them out.
[149] In another embodiment, conventional plugs are set, used, and drilled out
to a TMD of about 20,000 feet. Beyond that depth, degradable plugs or
ball/plug
combinations as set forth herein are used. Following use, such as in fracing,
the
conventional plugs Cp are drilled out in ways known in the art and the
degradable plugs
are left to dissolve.
[150] In one test, a snub nose plug 700 (see Fig. 7) was provided with all
elements of the plug except for the slips and rubber (elastomer) being made of
PGA.
The plug was tested under the following conditions: 200 F, 3,500 psi, @ 9:00
hours.
The results were the plug "let go" or quit holding pressure after 9:00 hours @
about
200 F.
[151] In an alternate embodiment, Applicants use the combination of (1) a low
metallic content easily drilled out composite plug or a conventional plug in
an upper
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portion of the well with (2) plugs with degradable elements according to any
of the
embodiments set forth herein in a lower portion of the well. In
the alternate
embodiment, a ball drop plug can be used wherein the ball is a degradable
ball, for
example, a PGA ball as described herein, along with a composite or
conventional plug,
wherein the ball disintegrates over time due to heat and fluid contact. The
remaining
composite plug may be either left in the well or may be drilled out at a later
more
convenient time. In a preferred embodiment, the plugs used in the extended
reach
have a minimum inner diameter of .50 inches.
[152] In another embodiment, an entire well is fraced using only frac plugs as
disclosed herein, that is, plugs which are at least partially comprised of
degradable
materials, or are conventional frac plug designs using degradable balls or
plug
elements. In the embodiments set hereinabove, the well typically has a
horizontal
portion.
[153] Figs. 21A and 21B illustrate the use of elastomeric elements in downhole
plugs. in ways known in the art, plugs are set by setting tools, driving
UOIlb, and
applying compression to elastomeric elements so they expand against the inside
wall of
downhole casings, which sets the plug. Non-degradable elastomeric elements are
known in the art For example, Nitrile having a Shore A durometer hardness of
between
60 and 90 is available from variety of rubber vendors. However, typical
elastomeric
expandable setting elements do not quickly break down or degrade downhole and
may
clog or interfere with fluid circulation and production. Applicants provide,
in Figs. 21A
and 21B, elastomeric elements 1500 designed to degrade into environmentally
harmless elements within days, months or years of their placement downhole.
The
dimensions of Applicant's degradable elastomeric elements 1500 may be the same
or
similar to those in the prior art, their novelty being primarily in their
predetermined
temporal degradability. For example, in Fig. 21A, degradable elastomeric
element 1500
is comprised of three pieces, center element 1502 and end elements 1504. In
Fig. 21B,
the degradable element is a single piece.
[154] The breakdown times of the described degradable elastomeric element
will vary according to local conditions and elastomeric element composition.
One useful
result is sufficient elastomeric element degradation within a predetermined
time such
that it fragments into smaller pieces which may be more easily circulated out
or which
do not materially interfere with circulation or production. Useful
predetermined times for
the elastomeric element to break into smaller pieces are within 48 hours, one
week, one
month or more. This avoids elastomeric elements in the well interfering with
production.
[155] A rigid durable strong anti-extrusion (anti-deformation) base or member
1506 may be provided adjacent either end elements or either ends of the one-
piece
element illustrated in Fig. 21B, the anti-extrusion members 1506 being
configured to lay
adjacent the perpendicular end walls of the element and at least partially
adjacent the
conical side walls 1500a. Compression of the elastomer 1500 by elements on
either
side in ways known in the art causes cone or cones 1508 to push the elastomer
outward and against the inner walls of the wall casing. Anti-extrusion base or
member
1506 forces the elastomer top to expand in the directions indicted by the
arrows in Fig.
21B rather than bulging sideways.
[156] The material or materials that may, in one embodiment, comprise
Applicant's biodegradable elastomer may be found in Publication US
2011/0003930,
which discloses an elastomeric polymeric material
having a hardness from 50 on the Shore A scale to 65 on the Shore D scale. It
discloses a biodegradable elastomer compound with suitable hardness. The
elastomer
may be molded, over-molded or extruded.
[157] Another degradable material of sufficient strength and hardness may be
found in US 7,661,541. This
patent discloses the use
of polymers alone, as co-polymers or blends thereof, the selection of which
polymer
combinations will depend on the particular application and include
consideration of
factors such as tensile strength, elasticity, elongation, modulus, toughness,
and
viscosity of liquid polymer, to provide the desired characteristics.
[158] The '541 patent discloses both polyether polyurethanes and polyester
polyurethanes elastomeric biodegradable elements suitable for use in downhole
tools.
The degree of biostability as well the mechanical characteristics can be
modified by, for
example, varying the molecular weight of the polymers and using techniques and
designs known in the art of, for example, biodegradable elastomers for medical
use.
Some commercial available segmented polyurethanes as disclosed in the '541
41
CA 2895507 2017-06-08
reference are: BiomerTm (Ethicon Inc., Somerville, NJ); PelletheneTM (Dow
Chemical,
Midland, Michigan); and TicoflexTm (Carmedix, Inc., Wolbang, Mass). Of these,
the
Pellethene in particular (including a number of embodiments of Pellethenee)
may be
designed with the mechanical characteristics and hardness, as well as
elastomeric and
biodegradable properties, needed for use as a degradable elastomer in downhole
tools.
[159] Prior art elastomers typically have hard nesses of about 60 to 95, in
either
a single elastomer or segmented (three part) elastomer as illustrated.
However, in one
embodiment, Applicant's degradable elastomer initially has the mechanical and
dimensional characteristics of prior art elastomers, and is, in one
embodiment, in a
durometer range of about 40 to 60 Shore A, and uses the anti- extrusion base
or
member 1506 as illustrated. In another embodiment it may be in the hardness
range of
40 to 95 Shore A. Both suitable biodegradable elastomers may be found in US
Patent
Nos. 4,045,418; 4,047,537; and 4,568,253.
These disclose elastomers with appropriate hardness and provide
thermoplastic biodegradability in an elastomer that may be deformed under the
compression conditions of downhole tools.
[160] Figs. 22A, 22B, 22C, and 22D illustrate a multi-component slip 1600 that
may be made of a metallic component 1602, such as steel or cast iron,
typically
comprising the outer portion of the multi-component 1600, and a non-metal,
degradable
component 1604 typically comprising all or a portion of the inner walls of the
multi-
component slip as seen in Fig. 22A. Fig. 22A is an exploded figure showing the
at least
two components together on the left and exploded out to the right showing the
non-
metallic degradable component 1604.
[161] Applicant's multi-component slips 1600 are designed typically with the
same dimensions and functionality of prior art slips, but having degradable
component
1604, including at least a portion of the inner walls of the multi-component
slip allows for
quicker tool breakdown and less debris remaining in the casing.
[162] One or more of teeth 1606, leading edge 1608, and base 1610 may be at
least, in part, a metallic element, such as iron or tungsten carbide. Some of
inner walls
1612 may comprised of the degradable component 1604 and typically have at
least
partially conical walls 1614 that will function normally as conical inner
walls of a slip to
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drive teeth 1606 into the inner walls of the casing. Yet they will decompose
or degrade
in fluid at the pressures and temperatures found in especially deep or long
reach wells
where milling out is difficult. Slots 1616 and reciprocal ridges may be
provided in at
least a portion of degradable component 1604 and metallic component 1602.
Degradable component 1604 may have a base 1618 with an inner diameter
configured
to slidingly engage the mandrel or other structural member.
[163] Fig. 220 illustrates an alternate preferred embodiment of multi-
component
slip 1600 showing a base configured to extend past the trailing edge of the
metal
component and with inner walls configured to at least partially ride on the
mandrel and
inner walls that are least partially conical.
[164] The degradable material may be non-metallic, homogenous, and may be
polyglycolic acid as set forth herein or any other suitable degradable
material. The
degradable material will degrade in fluid (including acidic or non-acidic
fluid) at the
downhole temperature and conditions described herein and detach from metallic
component 1602, to leave only the metallic elements remaining on the slip. The
degradation into smaller fragments is accomplished within a predetermined
time, such
as one day, one week, one month or more, which do not substantially interfere
with
producing the well. In an alternate embodiment, the material is not
degradable, but it is
a substantially non-metallic composite fiber, such as a spun filament and
resin
composition, such as is available from Columbia Industrial Plastics of Eugene,
Oregon.
It may be machined or molded onto the slip. The degradable/composite element
may
be separately machined and glued to the metallic elements of the slip by a
suitable
adhesive. In another embodiment, a tongue and groove may be used to engage the
at
least two components. The degradable or drillable non-metallic supporting
element of
the slip supporting metallic component 1602 reduce the problems caused by hard
metallic slips in the well.
[165] Figs. 23A, 23B, and 23C provide views of a novel slip comprising a
degradable slip body 1702, which is configured to receive multiple inserts
1704, such as
insert 1704 comprising carbide, iron, tungsten carbide, ceramic mixes or other
hard
materials known in the art. The inner walls of degradable body 1702 may be
configured
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in ways known in the art, typically including a conical section and a
cylindrical mandrel
engaging section.
[166] Referring to Figs. 24A and 24B, there is illustrated an exemplary
flapper
valve assembly 1830 that may be used as described above in connection with
vertical
or horizontal wells. The flapper valve assembly 1830 comprises, as major
structural
members, a tubular housing or sub 1868, a flapper valve member 1836 and a
sliding
sleeve 1870 or other suitable mechanism for holding the valve member 1836 in a
stowed or inoperative position. Any conventional device may be used to shift
the sliding
sleeve 1870 between the position shown in Fig. 24A where the valve member 1836
is
held in an inoperative position to the position shown in Fig. 24B where the
valve
member 1836 is free to move to a closed position blocking downward movement of
pumped materials through the flapper valve assembly 1830. Although the
mechanism
disclosed to shift the sleeve 1870 is mechanical in nature, it will be
apparent that
hydraulic means are equally suitable.
[167] A tubular housing 1868 comprises a lower section 1872 having a threaded
lower end 1874 matching the threads of the collars in casing strings 1822,
1848, a
central section 1876 threaded onto the lower section 1872 and providing one or
more
seals 1878 and an upper section 1880. The upper section 1880 is threaded onto
the
central section 1876, provides one or more seals 1882 and a threaded box end
1884
matching the threads of the pins of pipe joints 1824, 1850. The upper section
1880 also
includes a smooth walled portion 1886 on which the sliding sleeve 1870 moves.
[168] The function of the sliding sleeve 1870 is to keep the flapper valve
member 1836 in a stowed or inoperative position while the casing string is
being run
and cemented until such time as it is desired to isolate a formation below the
flapper
valve member 1830. There are many arrangements in flapper valves that are
operable
and suitable for this purpose, but a sliding sleeve is preferred because it
presents a
smooth interior that is basically a continuation of the interior wall of the
casing string
thereby allowing normal operations to be easily conducted inside the casing
string and it
prevents the entry of cement or other materials into a cavity 1888 in which
the valve
member 1836 is stowed.
44
[169] The sliding sleeve 1870 accordingly comprises an upper section 1890
sized to slide easily on the smooth wall portion 1886 and provides an 0-ring
seal 1892
which also acts as a friction member holding the sleeve 1870 in its upper
position. The
upper section 1880 of the tubular housing and the upper section 1890 of the
sliding
sleeve 1870 accordingly provide aligned partial grooves 1894 receiving an 0-
ring seal
1892. When the sleeve 1870 is pulled upwardly against the shoulder 1896, the 0-
ring
seal 1892 passes into a groove 1894 and frictionally holds the sleeve 1870 in
its upper
position.
[170] The upper section 1890 of the sliding sleeve 1870 provides a downwardly
facing shoulder 1998 and an inclined upwardly facing shoulder 1810 providing a
profile
for receiving the operative elements of a setting tool of conventional design
so the
sliding sleeve 1870 may be shifted from the stowing position of Fig. 3 to the
position of
Fig. 4, allowing the valve member 18356 to move to its operative position.
[171] The siding sleeve 1870 includes a lower section 1812 of smaller external
diameter than the upper section 1890 thereby providing the cavity 1888 for the
flapper
valve member 1836. In the down or stowing position ,the sliding sleeve 1870
seals
against the lower section 1872 of the tubular housing 1868 so that cement or
other
materials do not enter the cavity 1888 and interfere with operation of the
flapper valve
member 1836.
[172] The flapper valve member 1836 and any or all of the structural elements
of the flapper valve assembly 1830 may be made of any of the degradable
materials
disclosed herein, including polyglycolic acid.
Further details of the structure and
function of the flapper valve assembly may be found in US Patent No.
7,287,596.
Use of a flapper valve member which degrades
advantageously eliminates the need to mechanically remove the flapper valve
member,
such as with a rod, ball or drilling out.
[173] In specific embodiments, the structural elements set forth herein are
configured to be made from a high molecular weight polymer, including
repeating PGA
monomers include the tools seen in Figs. 1-14 or Fig. 19, or those set forth
in Magnum
Oil Tools International's Catalog, on pages C-1 through L-17.
CA 2895507 2017-06-08
CA 02895507 2016-10-07
074] While measured numerical values stated here are intended to be
accurate, unless otherwise indicated the numerical values stated here are
primarily
exemplary of values that are expected. Actual numerical values in the field
may vary
depending upon the particular structures, compositions, properties, and
conditions
sought, used, and encountered. The above-described embodiments are intended to
be
examples only. Alterations, modifications and variations can be effected to
the particular
embodiments by those of skill in the art without departing from the scope,
which is defined
solely by the claims appended hereto.
46
