Note: Descriptions are shown in the official language in which they were submitted.
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METHOD AND SYSTEM FOR FRACKING ANC COMPLETING WELLS
[0001] (This paragraph intentionally left blank.)
Background
10002] Oil and gas wells can be treated by fracking (hydraulic fracturing) and
chemical injections to increase production. The fracking process occurs after
a bore
hole has been formed through a formation, and is sometimes referred to as
completing
the well. Fracking forms fractures in a formation that are typically oriented
parallel to
the maximum induced stresses i a the formation and perpendicular to the
minimum
induced stresses in the formation. Following (or during) fracking, a granular
proppant
material can be injected into the fractures to hold them open. The fractures
provide
low resistance flow paths through the formation into the well liner. Chemical
injections can also be used separately, or in combination with fracking, to
increase
flow capacity by dissolving materials or changing formation properties.
[0003] One fracking method involves drilling a horizontal well bore, and
inserting a liner into the well bore. The annulus between the liner and the
well bore is
then filled with cement. The liner is then perforated in sections of typically
from 100
to 1000 feet using a perforating device. In addition, a packer on a coiled
tubing string
can be placed at the lower end of the segment and actuated to establish a
hydraulic
seal. Hydraulic fracturing can then be performed in the sealed perforated
segment.
The packer can then be released and moved to repeat the process.
[0004] This prior art fracking method is expensive as the well bore is
relatively large and the liner must be made of high strength steel and
cemented in
place. In addition, in non-cemented liners, the packers have a limited life
expectancy
and a low reliability. Also due to the complexity of the method, only a
limited
number of stages can be performed. For example, a 4000 feet horizontal well
bore
can typically only be treated in 10 stages of 400 feet with each stage having
3-4
perforated zones. Another problem is that the high pressures needed for
hydraulic
fracturing can damage cemented liners.
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[0005] The present disclosure is directed to a method and system for fracking
and completing wells that is better, faster and cheaper than prior art methods
and
systems. In particular, lower cost materials are used, and the downhole
perforating
operation and external liner pockets are eliminated. Further, more stages can
be
performed, more fractures can be formed, more proppant can be injected and
higher
flow rates can be achieved.
[0006] However, the foregoing examples of the related art and limitations
related therewith are intended to be illustrative and not exclusive. Other
limitations of
the related art will become apparent to those of skill in the art upon a
reading of the
specification and a study of the drawings.
Summary
[0007] A method for fracking and completing a well having a well bore
through a formation includes the steps of: packer jack fracking a first
interval of the
formation using a packer to form a first packer fractured formation, deflating
and
moving the packer to a second interval in the formation; inflating the packer
to seal
the first packer fractured formation; hydraulically fracturing the first
packer fractured
formation by injecting a fracking fluid through the packer, and then repeating
the
packer jack fracking step, the deflating and moving the packer step, the
inflating the
packer step and the hydraulically fracturing step through successive intervals
of the
formation. To complete a new well, a perforated liner can be placed in a well
bore to
direct the fracking fluid into the packer fractured formation. To complete an
existing
or new well having a cemented liner, the packer jack fracking step can also be
used to
break apart the liner to provide flow paths for the fracking fluid through the
casing
into the packer fractured formation.
[0008] For completing a new well, the method can include the steps of:
installing a perforated liner in the well bore having a plurality of pre-
formed openings
therethrough; installing a packer in the perforated liner at a first interval
in the
formation; packer jack fracking the first interval using the packer to define
a first
packer fractured formation; deflating and moving the packer to a second
interval in
the formation; inflating the packer to seal the first packer fractured
formation;
hydraulically fracturing the first packer fractured formation by injecting a
fracking
fluid through the packer and the openings in the perforated liner to form a
first
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hydraulically fractured formation; and packer jack fracking the second
interval using
the packer to define a second packer fractured formation. The hydraulically
fracturing
step, the deflating and moving step, the inflating step, and the packer
fracturing step
of the method can then be repeated through as many intervals as is necessary.
Optionally, rather than a single packer, a second packer can be used to seal
the
intervals. For completing an existing or a new well having a liner cemented in
the
well bore, the method can include essentially the same steps, but without
installing the
perforated liner and with the packer jack fracking step performed to break at
least one
opening through the cemented liner.
[0009] A system for fracking and completing a well having a well bore
through a formation comprises: a perforated liner in the well bore having a
plurality
of pre-formed openings therethrough, a high pressure drill pipe, a packer
actuation
tool and a packer in the perforated liner configured to fracture and seal
successive
intervals in the formation.
Brief Description of the Drawings
[0010] Exemplary embodiments are illustrated in the referenced figures of the
drawings. It is intended that the embodiments and the figures disclosed herein
be
considered illustrative rather than limiting.
[0011] Figure 1 is a schematic cross sectional view illustrating the step in
the
method of installing a perforated liner in the bore hole;
[0012] Figure 2 is a schematic cross sectional view illustrating the step in
the
method of installing a packer at a first interval of the formation;
[0013] Figure 2A is a schematic perspective view of the packer taken along
section line 2A-2A of Figure 2 and partially cut away to illustrate a
reinforced
inflatable element of the packer;
[0014] Figure 2B is a schematic cross sectional view with parts removed taken
along section line 2B-2B of Figure 2A illustrating a grooved outer cover of
the
packer;
[0015] Figure 3 is a schematic cross sectional view illustrating the step in
the
method of packer jack fracking using the packer to form a first packer
fractured
formation;
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[0016] Figure 3A is a schematic cross sectional view taken along section line
3A-3A of Figure 3 illustrating primary packer jack fracs in the first packer
fractured
formation;
[0017] Figure 3B is a schematic cross sectional view taken along section line
3B-3B of Figure 3 illustrating primary and secondary packer jack fracs in the
first
packer fractured formation;
[0018] Figure 4 is a schematic cross sectional view illustrating the step in
the
method of deflating and moving the packer to a second interval in the
formation;
[0019] Figure 5 is a schematic cross sectional view illustrating the step in
the
method of hydraulically fracturing the first packer fractured formation by
inflating the
packer to seal the bore hole and injecting a fracking fluid through the packer
and the
openings in the perforated liner to form a first hydraulically fractured
formation with
an optional step in the method of using a second packer to seal the first
hydraulically
fractured formation shown in phantom lines;
[0020] Figure 6 is a schematic cross sectional view illustrating the step in
the
method of packer jack fracking the second interval using the packer to define
a
second packer fractured formation;
[0021] Figure 7 is a schematic cross sectional view taken along section line 7-
7 of Figure 6 illustrating primary packer jack fracs in the second packer
fractured
formation;
[0022] Figure 7A is a schematic cross sectional view equivalent to Figure 7
illustrating primary and secondary packer jack fracs in the second packer
fractured
formation;
[0023] Figure 8 is a schematic cross sectional view taken along section line 8-
8 of Figure 6 illustrating primary hydraulic fracs in the first hydraulically
fractured
formation;
[0024] Figure 8A is a schematic cross sectional view equivalent to Figure 8
illustrating primary and secondary hydraulic fracs in the first hydraulically
fractured
formation;
[0025] Figure 9 is a schematic cross sectional view equivalent to Figure 1
illustrating a step in an alternate method performed on a well having a liner
cemented
in the well bore;
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[0026] Figure 9A is a cross sectional view taken along section line 9A-9A of
Figure 9;
[0027] Figure 10 is a schematic cross sectional view equivalent to Figure 2
illustrating the step in the alternate method of installing a packer at a
first interval of
the formation;
[0028] Figure 11 is a schematic cross sectional view equivalent to Figure 3
illustrating the step in the alternate method of breaking apart the cemented
liner and
packer jack fracking the formation using the packer to form a first packer
fractured
formation;
[0029] Figure 11A is a schematic cross sectional view taken along section line
11A-11A of Figure 11 illustrating an opening through the cemented liner and
primary
packer jack fracs in a first packer fractured formation;
[0030] Figure 12 is a schematic cross sectional view equivalent to Figures 4
and 5 illustrating the steps in the method of deflating and moving the packer
to a
second interval in the formation, inflating the packer to seal the bore hole,
and
hydraulically fracturing the first packer fractured formation by injecting a
fracking
fluid through the packer and the opening in the cemented liner to form a first
hydraulically fractured formation;
[0031] Figure 12A is a schematic cross sectional view taken along section line
12A-12A of Figure 12 illustrating formation of the first hydraulically
fractured
formation;
[0032] Figure 13 is a schematic cross sectional view equivalent to Figure 2
illustrating an optional step in the alternate method of using a second packer
to seal
the first hydraulically fractured formation;
[0033] Figure 14 is a schematic cross sectional view illustrating the step in
the
alternate method of packer jack fracking the second interval using the packer
to define
a second packer fractured formation;
[0034] Figure 14A is a schematic cross sectional view taken along section line
14A-14A of Figure 14 illustrating formation of a second packer fractured
formation;
[0035] Figure 15 is a schematic cross sectional view illustrating the step in
the
alternate method of hydraulically fracturing the second packer fractured
formation by
injecting a fracking fluid through the packer and the opening in the cemented
liner to
form a second hydraulically fractured formation; and
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[0036] Figure 15A is a schematic cross sectional view taken along section line
15A-15A of Figure 15 illustrating formation of the second packer fractured
formation.
Detailed Description
[0037] Figures 1-6 illustrate steps in a method for fracking and completing a
well 10. The well 10 can comprise an oil and gas well or alternately another
type of
well, such as another gas or liquid well such as a recharge water well.
Referring to
Figure 1, the well 10 includes a well bore 12 that extends from a ground
surface into a
geological formation 14 at a required depth of typically from several hundred
to
several thousand feet. The well bore 12 extends through the geological
formation 14
in a generally horizontal direction. The well bore 12 can also include a
vertical
segment, which for simplicity is not shown. The well bore 12 can be smaller
than in a
conventional oil and gas well. For example, a representative diameter of the
well
bore 12 can be about 6 inches to 8 inches.
[0038] As shown in Figure 1, the method includes the step of installing a
perforated liner 16 in the well bore 12 having a plurality of pre-formed
openings 18
therethrough. The perforated liner 16 can comprise metal pipe that has been
formed or
machined with the openings 18 through the sidewalls, and attached in lengths
by
welding or threaded connections. As the perforated liner 16 has no pressure
requirements, it can be made of low strength steel with seams, rather than
high
pressure seamless steel as with a conventional well liner. Further, the
perforated liner
16 can be made relatively cheaply relative to a well liner perforated with an
in-hole
perforating device, and does not require cementing as with a conventional
perforated
well liner.
[0039] As shown in Figure 1, the diameter D of the perforated liner 16 can be
slightly less than the diameter of the well bore 12, such that an annulus 20
is formed
between the perforated liner 16 and the well bore 12. A representative
diameter D of
the perforated liner 16 can be about 5 inches for a 6.25 to 6.75 inch
horizontal well
bore, but other diameters for these elements can be used. A diameter Do of the
openings 18 can be selected as required with from 1/8 inch to 3/4 inch being
representative. Further, the density of the openings 18 can be selected as
required
with up to 500 openings per linear foot being representative. This density is
larger
than for openings formed in a conventional well liner by a down-hole
perforating
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device. The larger number of openings 18 provides reduced fracturing flow
resistances and increased production flow rates compared to a conventional
perforated
well liner. The openings 18 can also be formed with chamfered edges to further
reduce flow resistances and increase flow rates.
[0040] Referring to Figure 2, the method also includes the step of installing
a
packer 22 in the perforated liner 16 at a first interval Ii in the formation
14, which is
configured to perform a packer jack frac. As used herein, the term "packer
jack frac"
refers to a fracturing process that depends on a mechanical jacking force
exerted on
the formation 14 by the packer 22. By way of example, with the packer 22
inflated to
a pressure of from 10,000 psia to 30,000 psia, enough force is produced to
fracture the
formation 14. Further details of the packer jack frac will become more
apparent as
the description proceeds.
[0041] The packer 22 is attached to a high pressure tubular 24 and is
controlled by a packer actuation tool 26. The packer 22 can comprise a fixed
head
inflatable packer or a sliding head inflatable packer. One suitable packer is
described
in US Patent No. 5,778,982, which is incorporated herein by reference. Other
suitable
packers are commercially available from Baski Inc. of Denver, CO. As shown in
Figure 2A, the packer 22 includes a tubular packer mandrel 32 and an
inflatable
element 34 attached to the packer mandrel 32 at both ends connected to an
inflation
tube 42. The packer 32 is shown in an uninflated condition in Figure 2A. The
inflatable element 34 comprises a multi layered structure formed of separate
layers or
plies of resilient elastomeric materials. More specifically, the inflatable
element 34
includes an inner layer 44, middle layers 46, 48 and outer layer 50. As shown
in
Figure 2B, the outer layer 50 of the inflatable element 34 can include a
plurality of
radially spaced circumferential grooves 62 having a desired depth configured
to
provide a higher frictional force for anchoring the packer 22 to the well bore
12 (or to
a liner 58 as will be hereinafter described). This permits higher forces to be
applied to
the formation 14 by the packer 22 as anchoring friction is maximized due to a
higher
pressure being applied to the well bore 12 or the perforated liner 16. A
packer having
an outer member with a grooved construction is further described in US Patent
No.
7,721,799, which is incorporated herein by reference.
[0042] As also shown in Figure 2A, the middle layers 46, 48 can comprise an
elastomeric base material reinforced with reinforcing material 52. The
reinforcing
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material 52 can comprise fibers, cable or cord embedded in the elastomeric
base
material at a desired spacing "x" and a desired angle "a". The construction of
the
inflatable element 34 allows high pressures and mechanical jacking forces to
be
achieved. In addition, the inflatable element 34 is designed to return to its
uninflated
shape for moving the packer 22 to other locations in the well bore 12.
Further, the
construction of the inflatable element 34 permits the packer 22 to be easily
cycled
from an inflated to an uninflated condition to cycle the mechanical jacking
forces.
[0043] The high pressure tubular 24 can comprise lengths of steel tubing that
are joined together by threaded connections. In addition, to placing the
packer 22 at a
desired location, the high pressure tubular is designed to contain the
fracking fluid 30
during a hydraulic fracturing step to be hereinafter described. The packer
actuation
tool 26 is configured to inflate and deflate the packer 22 upon manipulation
of the
tubular 24 from the surface. This type of tool is also commercially available
from
Baski Inc. of Denver, CO.
[0044] Referring to Figure 3, the method also includes the step of packer jack
fracking the first interval Ii using the packer 22 to define a first packer
fractured
formation 28. This step can be performed by inflating the packer 22 to a
desired
pressure of from 10,000 psia to 30,000 psia for a desired time period of from
minutes to hours. This step can also be performed by cycling the packer 22
from an
uninflated to an inflated condition over a selected cycle time period of from
seconds
to hours. As shown in Figures 3A and 3B, the packer jack fracking step forms
primary packer jack fracs 36 and possibly secondary packer jack fracs 38. The
primary packer jack fracs 36 are oriented generally perpendicular or
orthogonal to the
ground surface. The secondary packer jack fracs 38 are oriented generally
parallel to
the ground surface. As shown in Figure 4, the perforated liner 16 has also
been
deformed in the first packer fractured formation 28.
[0045] Referring to Figure 4, the method also includes the step of deflating
and moving the packer 22 to a second interval 12 in the formation 14. The
intervals Ii
and 12 can be adjacent to one another or can be spaced with a desired spacing.
[0046] Referring to Figure 5, the method also includes the step of inflating
the
packer 22 to seal the first packer fractured formation 28 for the subsequent
hydraulic
fracturing step. Preferably this step is performed such that plastic
deformation of the
perforated liner 16 occurs as indicated by the deformed outwardly bulging
portion of
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the liner 16 in Figure 5. The packer 22 seals the up hole end of the well bore
12
proximate to the second interval 12. The down hole end of the well bore 12 can
be
unsealed, or optionally, as shown by the phantom lines in Figure 5 a second
packer
22A can be used to seal the down hole end of the well bore 12. The second
packer
22A can be spaced from the packer 22 with a required spacing, and can be
placed and
controlled using a second passageway, which for simplicity is not shown. With
this
method of control, the second packer 22A can be attached to the same high
pressure
tubular 24 and packer actuation tool 26 as the packer 22.
[0047] As also shown in Figure 5, the method also includes the step of
hydraulically fracturing the first packer fractured formation 28 by injecting
a fracking
fluid 30 through the packer 22 and the openings 18 in the perforated liner 16
to form a
first hydraulically fractured formation 40. During this step, the packer 22
seals the up
hole end of the well bore 12. In addition, the fracking fluid 30 can be
injected from
the surface through the high pressure tubular 24, through the packer 22 and
through
the openings 18 in the perforated liner 16 into the first packer fractured
formation 28.
In addition to the fracking fluid 30, chemicals and proppants can also be
injected into
the first hydraulically fractured formation 40.
[0048] Referring to Figure 6, the system 54 includes the packer 22 and the
perforated liner 16. As shown in Figure 6, the method also includes the step
of packer
jack fracking the second interval 12 using the packer 22 to define a second
packer
fractured formation 56. This step can be performed as previously described for
packer jack fracking of the first interval Ii. Figures 7 and 7A illustrate the
fracking
fluid 30 being injected through the packer and into the primary packer jack
fracs 36
and the secondary packer jack fracs 38 (Figure 7A). Figures 8 and 8A
illustrate the
formation of the first hydraulically fractured formation 40 by injection of
the fracking
fluid 30 into the primary packer jack fracs 36 and the secondary packer jack
fracs 38
(Figure 7A) to form a plurality of hydraulic fractures 56 (Figure 8A).
[0049] The hydraulically fracturing step (Figure 5) can then be repeated as
previously described to form a second hydraulically fractured formation in the
second
interval 12. In addition, the deflating and moving step (Figure 4), the
inflating step
(Figure 4), and the packer fracturing step (Figure 3) of the method can then
be
repeated through as many intervals as is necessary.
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[0050] Figures 9-15 illustrate steps in an alternate method for fracking and
completing a well 10A. As shown in Figures 9 and 9A, the well 10A includes a
well
liner 58 cemented in a well bore 12A with cement 60.
[0051] Referring to Figure 10, the alternate method also includes the step of
installing the packer 22 in the liner 58 at a first interval Ii in the
formation 14. This
step can be performed substantially as previously described and shown in
Figure 2.
[0052] Referring to Figure 11 and 11A, the alternate method also includes the
step of breaking apart the liner 58 and the cement 60 to form at least one
opening 64
through the liner 58 and the cement 60. Although for illustrative purposes
only one
opening 64 is shown, this step can be performed to form a plurality of
openings 64 to
provide multiple flow paths through the liner 58 and the cement 60. During
this step
the packer 22 also performs packer jack fracking of the first interval Ii to
define the
first packer fractured formation 28. This step can be performed substantially
as
previously described and shown in Figure 3. As also shown in Figure 11, a
geophone
66 at the surface can be used to monitor the step.
[0053] Referring to Figures 12 and 12A, the alternate method also includes
the step of deflating and moving the packer 22 to a second interval 12 in the
formation
14 and inflating the packer 22 to seal the first packer fractured formation 28
for the
subsequent hydraulic fracturing step. The packer 22 seals the up hole end of
the well
bore 12 proximate to the second interval 12. The down hole end of the well
bore 12
can be unsealed, or optionally, as shown in Figure 13, a second packer 22A can
be
used to seal the down hole end of the well bore 12. The second packer 22A can
be
attached to a tubular 60 having a slot 70 for providing a flow path for the
hydraulic
fracturing step.
[0054] As also shown in Figure 12, the alternate method also includes the step
of hydraulically fracturing the first packer fractured formation 28 by
injecting the
fracking fluid 30 through the packer 22 and the openings 64 in the liner 58
and the
cement 60 to form a first hydraulically fractured formation 40. During this
step, the
fracking fluid 30 can be injected from the surface through the high pressure
tubular
24, through the packer 22 and through the opening 64 in the liner 58 and the
cement
60 into the first packer fractured formation 28. In addition to the fracking
fluid 30,
chemicals and proppants can also be injected into the first hydraulically
fractured
formation 40.
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[00551 Referring to Figures 14 and 14A, the alternate method also includes
the step of packer jack fracking the second interval 12 using the packer 22 to
define a
second packer fractured formation 56. This step can be performed as previously
described for packer jack fracking of the first interval II.
100561 Referring to Figures 15 and 15A, the alternate method also includes
the step of hydraulically fracturing the second packer fractured formation 56
by
injecting the fracking fluid 30 through the packer 22 and the openings 64 in
the liner
58 and the cement 60 to form a second hydraulically fractured formation 72.
[00571 The scope of the claims should not he limited by the preferred
embodiments set forth in the examples, but should be given the broadest
interpretation
consistent with the description as a whole.
