Note: Descriptions are shown in the official language in which they were submitted.
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METHOD FOR AVOIDING FRAC HITS
DURING FORMATION STIMULATION
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[001] Not applicable.
THE NAMES OF THE PARTIES TO A JOINT RESEARCH AGREEMENT
[002] Not applicable.
STATEMENT OF RELATED APPLICATIONS
[003] This application claims the benefit of U.S. Provisional Patent Appl.
No. 62/617,108
filed January 12, 2018. That application is entitled "Method of Avoiding Frac
Hits During
Formation Stimulation."
[004] This application is also a Continuation-In-Part of U.S. Patent Appl.
No. 15/009,623
filed January 28, 2016. That application is entitled "Method of Forming
Lateral Boreholes From
A Parent Wellbore."
[005] The parent application claims the benefit of U.S. Provisional Patent
Appl. No.
62/198,575 filed July 29, 2015. That application is entitled "Downhole
Hydraulic Jetting
Assembly, and Method for Forming Mini-Lateral Boreholes." The parent
application also claims
the benefit of U.S. Provisional Patent Appl. No. 62/120,212 filed February 24,
2015 of the same
title.
[006] These applications are all incorporated by reference herein in their
entireties.
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BACKGROUND OF THE INVENTION
[007] This section is intended to introduce selected aspects of the art,
which may be
associated with various embodiments of the present disclosure. This discussion
is believed to
assist in providing a framework to facilitate a better understanding of
particular aspects of the
present disclosure. Accordingly, it should be understood that this section
should be read in this
light, and not necessarily as admissions of prior art.
Field of the Invention
[008] The present disclosure relates to the field of well completion. More
specifically, the
present disclosure relates to the completion and stimulation of a hydrocarbon-
producing
formation by the generation of small diameter boreholes from an existing
wellbore using a
hydraulic jetting assembly. The present disclosure further relates to the
controlled generation of
one or more lateral boreholes that extend into a subsurface formation while
minimizing or
completely avoiding "frac hits" in neighboring wellbores.
Discussion of Technology
[009] In the drilling of an oil and gas well, a near-vertical wellbore is
formed through the
earth using a drill bit urged downwardly at a lower end of a drill string.
After drilling to a
predetermined bottomhole location, the drill string and bit are removed and
the wellbore is lined
with a string of casing. An annular area is thus formed between the string of
casing and the
formation penetrated by the wellbore. Particularly in a vertical wellbore, or
the vertical section
of a horizontal well, a cementing operation is conducted in order to fill or
"squeeze" the annular
volume with cement along part or all of the length of the wellbore. The
combination of cement
and casing strengthens the wellbore and facilitates zonal isolation behind the
casing.
[0010] Advances in drilling technology have enabled oil and gas operators
to economically
"kick-off' and steer wellbore trajectories from a generally vertical
orientation to a generally
horizontal orientation. The horizontal "leg" of each of these wellbores now
often exceeds a
length of one mile, and sometimes two or even three miles. This significantly
multiplies the
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wellbore exposure to a target hydrocarbon-bearing formation (or "pay zone").
As an example,
consider a target pay zone having a (vertical) thickness of 100 feet. A one-
mile horizontal leg
exposes 52.8 times as much pay zone to a horizontal wellbore as compared to
the 100-foot
exposure of a conventional vertical wellbore.
[0011] Figure 1A provides a cross-sectional view of a wellbore 4 having
been completed in
a horizontal orientation. It can be seen that the wellbore 4 has been formed
from the earth surface
1, through numerous earth strata 2a, 2b,. . . 2h and down to a hydrocarbon-
producing formation
3. The subsurface formation 3 represents a "pay zone" for the oil and gas
operator. The wellbore
4 includes a vertical section 4a above the pay zone, and a horizontal section
4c. The horizontal
section 4c defines a heel 4b and a toe 4d and an elongated leg there between
that extends through
the pay zone 3.
[0012] In connection with the completion of the wellbore 4, several strings
of casing having
progressively smaller outer diameters have been cemented into the wellbore 4.
These include a
string of surface casing 6, and may include one or more strings of
intermediate casing 9, and
finally, a production casing 12. (Not shown is the shallowest and largest
diameter casing referred
to as conductor pipe, which is a short section of pipe separate from and
immediately above the
surface casing.) One of the main functions of the surface casing 6 is to
isolate and protect the
shallower, fresh water bearing aquifers from contamination by any wellbore
fluids. Accordingly,
the conductor pipe and the surface casing 6 are almost always cemented 7
entirely back to the
surface 1.
[0013] Surface casing 6 is shown as cemented 7 fully from a surface casing
shoe 8 back to
the surface 1. An intermediate casing string 9 is only partially cemented 10
from its shoe 11.
Similarly, production casing string 12 is only partially cemented 13 from its
casing shoe 14,
though sufficiently isolating the pay zone 3.
[0014] The process of drilling and then cementing progressively smaller
strings of casing is
repeated several times until the well has reached total depth. In some
instances, the final string
of casing 12 is a liner, that is, a string of casing that is not tied back to
the surface 1. The final
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string of casing 12, referred to as a production casing, is also typically
cemented 13 into place.
In the case of a horizontal completion, the production casing 12 may be
cemented, or may
provide zonal isolation using external casing packers ("ECP' s), swell
packers, or some
combination thereof.
[0015] Additional tubular bodies may be included in a well completion.
These include one
or more strings of production tubing placed within the production casing or
liner (not shown in
Figure 1A). In a vertical well completion, each tubing string extends from the
surface 1 to a
designated depth proximate the production interval 3, and may be attached to a
packer (not
shown). The packer serves to seal off the annular space between the production
tubing string
and the surrounding casing 12. In a horizontal well completion, the production
tubing is typically
landed (with or without a packer) at or near the heel 4b of the wellbore 4.
[0016] In some instances, the pay zone 3 is incapable of flowing fluids to
the surface 1
efficiently. When this occurs, the operator may install artificial lift
equipment (not shown in
Figure 1A) as part of the wellbore completion. Artificial lift equipment may
include a downhole
pump connected to a surface pumping unit via a string of sucker rods run
within the tubing.
Alternatively, an electrically-driven submersible pump may be placed at the
bottom end of the
production tubing. As part of the completion process, a wellhead 5 is
installed at the surface 1.
The wellhead 5 serves to contain wellbore pressures and direct the flow of
production fluids at
the surface 1.
[0017] Within the United States, many wells are now drilled principally to
recover oil and/or
natural gas, and potentially natural gas liquids, from pay zones previously
thought to be too
impermeable to produce hydrocarbons in economically viable quantities. Such
"tight" or
"unconventional" formations may be sandstone, siltstone, or even shale
formations.
Alternatively, such unconventional formations may include coalbed methane. In
any instance,
"low permeability" typically refers to a rock interval having permeability
less than 0.1
millidarcies.
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[0018] In order to enhance the recovery of hydrocarbons, particularly in
low-permeability
formations, subsequent (i.e., after perforating the production casing or
liner) stimulation
techniques may be employed in the completion of pay zones. Such techniques
include hydraulic
fracturing and/or acidizing. In addition, "kick-off' wellbores may be formed
from a primary
wellbore in order to create one or more new directionally or horizontally
completed boreholes.
This allows a well to penetrate along the depositional plane of a subsurface
formation to increase
exposure to the pay zone. Where the natural or hydraulically-induced fracture
plane(s) of a
formation is vertical, a horizontally completed wellbore allows the production
casing to intersect,
or "source," multiple fracture planes. Accordingly, whereas vertically
oriented wellbores are
typically constrained to a single hydraulically-induced fracture plane per pay
zone, horizontal
wellbores may be perforated and hydraulically fractured in multiple locations,
or "stages," along
the horizontal leg 4c, producing multiple fracture planes.
[0019] Figure 1A demonstrates a series of fracture half-planes 16 along the
horizontal
section 4c of the wellbore 4. The fracture half-planes 16 represent the
orientation of fractures
that will form in connection with a known perforating/fracturing operation.
The fractures are
formed by the injection of a fracturing fluid through perforations 15 formed
in the horizontal
section 4c.
[0020] The size and orientation of a fracture, and the amount of hydraulic
pressure needed to
part the rock along a fracture plane, are dictated by the formation's in situ
stress field. This stress
field can be defined by three principal compressive stresses which are
oriented perpendicular to
one another. These represent a vertical stress, a minimum horizontal stress,
and a maximum
horizontal stress. The magnitudes and orientations of these three principal
stresses are determined
by the geomechanics in the region and by the pore pressure, depth and rock
properties.
[0021] According to principles of geo-mechanics, fracture planes will
generally form in a
direction that is perpendicular to the plane of least principal stress in a
rock matrix. Stated more
simply, in most wellbores, the rock matrix will part along vertical lines when
the horizontal
section of a wellbore resides below 3,000 feet, and sometimes as shallow as
1,500 feet, below
the surface. In this instance, hydraulic fractures will tend to propagate from
the wellbore' s
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perforations 15 in a vertical, elliptical plane perpendicular to the plane of
least principle stress.
If the orientation of the least principle stress plane is known, the
longitudinal axis of the leg 4c
of a horizontal wellbore 4 is ideally oriented parallel to it such that the
multiple fracture planes
16 will intersect the wellbore at-or-near orthogonal to the horizontal leg 4c
of the wellbore, as
depicted in Figure 1A.
[0022] In actuality, and particularly in unconventional shale reservoirs,
resultant fracture
geometries are often more complex than a single, essentially two-dimensional
elliptical plane.
Instead, a more complex three-dimensional Stimulated Reservoir Volume ("SRV")
is generated
from a single hydraulic fracturing treatment. Hence, whereas for conventional
reservoirs the key
post-stimulation metric was propped frac length (or "half length") within the
pay zone, for
unconventional reservoirs the key metric is SRV.
[0023] In Figure 1A, the fracture planes 16 are spaced apart along the
horizontal leg 4c.
The desired density of the perforated and fractured intervals along the
horizontal leg 4c is
optimized by calculating:
= the estimated ultimate recovery ("EUR") of hydrocarbons each fracture
will
drain, which requires a computation of the SRV that each fracture treatment
will connect to the wellbore via its respective perforations; less
= any overlap with the respective SRV's of bounding fracture intervals;
coupled
with
= the anticipated time-distribution of hydrocarbon recovery from each
fracture;
versus
= the incremental cost of adding another perforated/fractured interval.
The ability to make this calculation and replicate multiple vertical
completions along a single
horizontal wellbore is what has made the pursuit of hydrocarbon reserves from
unconventional
reservoirs, and particularly shales, economically viable within relatively
recent times. This
revolutionary technology has had such a profound impact that currently Baker
Hughes Rig Count
information for the United States indicates only about one out of every
fifteen (7%) of wells
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being drilled in the U.S. are classified as "Vertical", whereas the remainder
are classified as
either "Horizontal" or "Directional" (85% and 8%, respectively). That is,
horizontal wells
currently comprise approximately six out of every seven wells being drilled in
the United States.
[0024] The additional costs in drilling and completing horizontal wells as
opposed to vertical
wells is not insignificant. In fact, it is not at all uncommon to see
horizontal well drilling and
completion ("D&C") costs top multiples (double, triple, or greater) of their
vertical counterparts.
Obviously, the vertical-vs-horizontal D&C cost multiplier is a direct function
of the length of
the horizontal leg 4c of wellbore 4.
[0025] Common perforation mechanisms are "plug-n-perf' operations where
sequences of
bridge plugs and perforating guns are pumped down the wellbore to desired
locations, or hydra-
jet perforations typically obtained from coiled tubing ("CT") conveyed
systems, the former being
perhaps the most common method. Though relatively simple, plug-n-perf systems
leave a series
of bridge plugs that must be later drilled out (unless they are dissolvable,
and hence, typically
more expensive), a function that becomes even more time consuming (and again,
more
expensive) as horizontal lateral lengths continue to get longer and longer.
Even more elaborate
mechanisms providing pressure communication between the casing I.D. and the
pay zone 3
include ported systems activated by dissolvable balls (of graduated diameters)
or plugs, or
sliding sleeve systems typically opened or closed via a CT-conveyed tool.
[0026] Important to the economic success of any horizontal well is the
achievement of
satisfactory SRV's within the pay zone being completed. Many factors can
contribute to the
success or failure in achieving the desired SRV's, including the rock
properties of the pay zone
and how these properties contrast with bounding rock layers both above and
below the pay zone.
For example, if either bounding layer is weaker than the pay zone, hydraulic
fractures will tend
to propagate out-of-zone into that weaker layer, thus commensurately reducing
the SRV that
might have otherwise been obtained. Similarly, pressure depletion from offset
well production
of the pay zone's reservoir fluids can significantly weaken the in situ stress
profile within the
pay zone itself. Stated another way, reservoir depletion that has occurred as
a result of
production operations in the parent wellbores will reduce pore pressure in the
formation, which
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reduces the principal horizontal stresses of the rock matrix itself The
weakened rock fabric now
superimposes a new "path of least resistance" for the high pressure frac
fluids during formation
stimulation. This means that fractures and fracturing fluids will now tend to
migrate toward
pressure depleted areas formed by adjacent wells.
[0027] In some instances, a sweeping of fracturing fluids towards a
producing well can be
beneficial, providing an increase in formation pressure and, possibly,
increased fracture
connectivity. This occurrence is sometimes referred to as a "pressure hit."
However, the
migration of fracturing fluids may also create an issue of redundancy. In this
respect, a portion,
if not a majority of costs of a child well's frac stage (including its
constituent frac fluids,
additives, proppant, hydraulic horsepower ("HHP") and other costs) is spent
building SRV in a
portion of the pay zone already being drained by the parent wellbore.
Additionally, there is now
child-vs-parent competition to drain reserves that would have eventually been
drained by the
parent alone.
[0028] In more extreme instances, pressure in an adjacent wellbore can
suddenly increase
significantly, such as up to 1,000 psi or greater. This is an obvious symptom
of fluid
communication between a child wellbore and the neighboring parent. This is
what is known as
a "frac hit." When a frac hit occurs, downhole production equipment in the
neighboring parent
wellbore can suffer proppant (typically sand) erosion, with the parent's
tubulars becoming filled
with sand. Events of collapsed casing, blown-out stuffing boxes and resultant
surface streams
of frac fluids have also been reported. The parent's previously productive
SRV's may never
recover. In a worst case scenario, the parent's tubulars and/or wellhead
connections may
experience failure associated with exposure to high burst and/or collapse
pressures.
Accordingly, frac hit damage may not be contained within the 'hit' parent
wellbore itself.
[0029] Those of ordinary skill in the art will appreciate that frac hits
are generally a by-
product of in-fill drilling, meaning that a new wellbore (sometimes referred
to as a "child well")
is being completed in proximity to existing wellbores (referred to as "offset"
or "parent wells")
within a hydrocarbon-producing field. Frac hits are also, of course, a by-
product of tight well
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spacing. Ultimately, however, frac hits are the result of the operator being
unable to control or
"direct" the propagation of fractures within the pay zone.
[0030] The problem of frac hits is receiving a great deal of attention in
the oil and gas
industry. It is estimated that in the last 18 months 100 technical papers have
been published.
Currently, a technical work dealing with "frac hits" is being produced every
2.75 working days.
This is in addition to the litigation that is taking place between well owners
and service
companies based on "improper drilling techniques." Quite often, a parent's hit
damage is
sometimes self-inflicted, that is, an operator is causing a frac-hit to occur
on its own offset well.
[0031] A "frac hits" lobbying group, the Oklahoma Energy Producers Alliance
("OEPA";
https://okenergyproducers.org/ ), has been recently formed. This organization
cites "Hundreds
if not thousands of wells are being destroyed by horizontal frac jobs...". The
group seeks to find
regulatory and legislative solutions to the problem of frac hits and the
protection of "vertical
rights" among operators. Partly as a result of efforts by the OEPA and groups
like it, many frac
operations now require notification of offset parent operators, affording them
the opportunity to
(before child frac), pull the rods, the pump, and the production tubing and to
strategically place
retrievable bridge plugs in order to preclude downhole and surface damages.
Such efforts are
commonly referred to as a "de-completion", and can cost upwards of $200,000
per well.
[0032] Accordingly, a need exists for controlling, directing, or at least
influencing the
directions and dimensions by which a hydraulic fracture ("frac") propagates
within a pay zone,
such that in-the-pay SRV can be created and frac hits can be minimized or
avoided altogether.
Thus, a need exists for a method of forming pre-frac mini-lateral boreholes
off of a parent
wellbore wherein the small, lateral boreholes are formed in controlled
directions and at pre-
selected lengths and configurations.
[0033] Additionally, a need exists for a method of forming lateral
boreholes wherein access
ports for the lateral boreholes can be selectively opened and closed along the
casing, thus
enabling pre-frac depletion of the rock matrix surrounding a selected mini-
lateral(s), with
commensurate weakening making them the new preferred paths for frac and SRV
propagation.
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A need further exists for a downhole casing collar having custom ports that
enable the boreholes
to be jetted through the ports in pre-set "east and west" directions.
[0034] Also, a need exists for a downhole assembly having a jetting hose
and a whipstock,
whereby the assembly can be conveyed into any wellbore interval of any
inclination, including
an extended horizontal leg. A need further exists for a hydraulic jetting
system that provides for
substantially a 900 turn of the jetting hose opposite the point of a casing
exit, preferably utilizing
the entire casing inner diameter as the bend radius for the jetting hose,
thereby providing for the
maximum possible inner diameter of jetting hose, and thus providing the
maximum possible
hydraulic horsepower to the jetting nozzle. A need further exists for a system
that includes a
whipstock deployable on a string of coiled tubing, wherein the whipstock can
be reoriented in
discreet, known increments, and not depend upon pipe rotation at the surface
translating
downhole.
[0035] Further, a need exists for a downhole jetting assembly that can, in
a single trip of the
assembly into the wellbore, repeatably generate both: (1) hydraulically jetted
casing exits and
subsequent mini-lateral boreholes from any point in the production casing;
and, (2) mateably
enjoin and operate ported casing collars, wherein the casing exits are pre-
formed by the ports
and jetting of mini-lateral boreholes into the pay zone is initiated
therefrom.
[0036] Additionally, a need exists for improved methods of forming lateral
wellbores using
hydraulically directed forces, wherein a desired length ofjetting hose can be
conveyed even from
a horizontal wellbore. Further, a need exists for a method of forming mini-
lateral boreholes off
of a horizontal leg wherein the extent of the mini-laterals is limited or even
avoided in a direction
of a neighboring wellbore.
[0037] A need further exists for a method of hydraulically fracturing mini-
lateral boreholes
jetted off of the horizontal leg of a wellbore immediately following lateral
borehole formation,
and without the need of pulling the jetting hose, whipstock, and conveyance
system out of the
parent wellbore. A need further exists for a method of controlling the
erosional excavation path
of the jetting nozzle and connected hydraulic hose, such that a lateral
borehole, or multiple lateral
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borehole "clusters," can be directed to avoid frac hits in an adjacent
wellbore during a subsequent
formation fracturing operation, or to enable newly created SRV to reach and
recover otherwise
stranded reserves.
SUMMARY OF THE INVENTION
[0038] The systems and methods described herein have various benefits in
the conducting
of oil and gas well completion activities. In the present disclosure, a method
of avoiding a frac
hit during a formation stimulation operation is first provided. The formation
stimulation
operation involves the forming of one or more small, lateral boreholes off of
a child wellbore.
The lateral boreholes are hydraulically excavated into a pay zone that exists
within a surrounding
rock matrix. The pay zone has been identified as holding, or at least
potentially holding,
hydrocarbon fluids or organic-rich rock.
[0039] The formation stimulation operation further includes the creation of
a fracture-
induced stimulated reservoir volume off of the lateral boreholes. This is done
by the injection
of a fracturing fluid into the lateral boreholes at high pressure.
Additionally, lateral boreholes
may be formed in groups, or clusters, and the fracturing process conducted in
stages, wherein a
cluster of lateral boreholes is "fracked" together. Alternatively, the mini-
lateral boreholes may
be isolated and fracked individually.
[0040] In one aspect, the method first comprises providing a child wellbore
within a
hydrocarbon-producing field. The child wellbore is either being completed as a
new well or
represents an existing well that is being recompleted. This new completion or
recompletion will
be in a specific pay zone that requires hydraulic fracturing for improved
production performance.
Preferably, the child wellbore is completed horizontally such that a
horizontal leg of the child
wellbore extends within the pay zone.
[0041] The method further comprises identifying an existing parent
wellbore. The parent
wellbore has been completed within the same hydrocarbon-producing field. The
parent wellbore
may be either a vertically, directionally, or horizontally drilled and
completed well. The parent
wellbore may have been completed, or completed and produced, in one or more
pay zones.
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[0042] In one aspect, the parent wellbore is completed in the same child-
targeted pay zone,
and has extracted significant production volumes from it, such that the
reservoir pressure in the
vicinity of the parent wellbore has been commensurately reduced. In this
instance, the parent
wellbore has created a "pressure sink" in the same pay zone targeted by the
child wellbore. The
result is that reservoir pressure in the vicinity of the parent wellbore is
less than that which the
child wellbore is targeting to drain. The reduction in pore pressure also
serves to weaken the
rock matrix in the pay zone adjacent the parent wellbore creating an
undesirable "path of least
resistance."
[0043] In another aspect, the child wellbore will be completed in a
different pay zone than
an offsetting parent wellbore. Notwithstanding, one or more hydraulic fracture
treatments of the
child well may frac through the boundary layers of its respective pay zone and
into the pay zone
of the parent wellbore. In these cases, the path-of-least-resistance towards
the parent wellbore
is still effective.
[0044] The method further includes conveying a hydraulic jetting assembly
into the child
wellbore. The hydraulic jetting assembly is transported into the wellbore on a
working string.
Preferably, the working string is a string of coiled tubing. This may include
coiled tubing having
one or more electrical wires ("e-coil") and, optionally, one or more fiber
optic data cables.
[0045] Generally, the hydraulic jetting assembly will include:
a whipstock providing a defined arcuate path for a jetting hose,
an elongated jetting hose having a proximal end and a distal end, and
a jetting nozzle disposed at a distal end of the jetting hose.
[0046] The downhole hydraulic jetting assembly is useful for jetting
multiple lateral
boreholes from a child wellbore into the subsurface formation. The assembly is
basically
comprised of two synergetic systems:
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(1) an internal system, which defines the jetting hose having at its proximal
end a
jetting fluid inlet, and at its terminal end the jetting nozzle, all being
configured to be
directed to and through a child wellbore exit location; and
(2) an external system that is run in on the coiled tubing, with the external
system
being configured to carry the jetting hose into the wellbore and "push" the
nozzle
against the whipstock set in the wellbore to urge the jetting nozzle forward
through
the exit location in the production casing, and on out into the surrounding
formation.
[0047] A window or "casing exit" is formed in the cased wellbore in one of
two ways: First,
a casing exit can be hydraulically jetted through the casing using the jetting
hose and connected
nozzle. In this instance, a high pressure jetting fluid (preferably with
abrasives) is directed
against the inner wall of the casing at the desired exit point. Alternatively,
a casing exit is
obtained by the alignment of pre-formed portals in a casing collar. In this
instance, the casing
collar is a novel, specially-fabricated tubular body included within the
production casing string
during the initial well completion. The casing collar employs pre-formed
portals that are
accessible when the position of an inner sleeve is manipulated by forces
exerted on it from within
by the whipstock.
[0048] Regardless of how the casing exit is obtained, window formation is
followed by the
formation of a lateral borehole out into the hydrocarbon-bearing pay zone. The
configuration
and operation of the synergetic internal and external systems provide that the
whipstock may be
re-oriented and/or re-located, and the jetting hose re-deployed into the
casing and re-retrieved,
for the jetting of multiple casing exits and lateral boreholes in the same
trip. The whipstock
includes a concave face for receiving and directing the jetting nozzle and
connected hose during
operation of the assembly. The curvature of the path designed for the jetting
hose, including its
trajectory along the face of the whipstock, bends the jetting hose such that
it will exit the casing
at or near a 90 angle relative to the longitudinal axis of the wellbore.
[0049] In one aspect, the whipstock is configured so that a face of the
whipstock provides a
bend radius for the jetting hose across the entire wellbore. In the case of a
cased hole, the jetting
hose will bend across the entire inner diameter of the production casing.
Thus, the hose contacts
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the production casing on one side, bends along the face of the whipstock, and
then extends to a
casing exit on an opposite side of the production casing. The jetting hose
bend radius spanning
the entire I.D. of the production casing provides for utilization of the
greatest possible diameter
of jetting hose, which in turn provides for maximum delivery of hydraulic
horsepower through
the jetting hose to the jetting nozzle.
[0050] In the case where the novel ported casing collar is used, the bend
radius provided for
the jetting hose may actually be greater than the casing I.D.
[0051] The hydraulic jetting assembly is configured to (i) translate the
jetting hose out of the
jetting hose carrier and against the arcuate whipstock face by a translation
force to a desired point
of wellbore exit, (ii) upon reaching the desired point of wellbore exit,
direct jetting fluid through
the jetting hose and the connected jetting nozzle, (iii) continue jetting
along an operator's
designed geo-traj ectory forming a lateral borehole into the rock matrix
within the pay zone, and
then (iv) pull the jetting hose back into the jetting hose carrier after a
lateral borehole has been
formed to allow the location of the whipstock device within the wellbore to be
adjusted.
[0052] Of interest, the lateral borehole may be formed at a desired depth,
a desired trajectory,
or both. The only limitation is the length of the jetting hose itself.
Optionally, the direction of
lateral borehole formation may be controlled by the use of a guidance system.
[0053] The external system is configured such that it contains, conveys,
deploys, and
retrieves the jetting hose of the internal system in such a way as to maintain
the hose in an
uncoiled state. Thus, the minimum bend radius that the hose must satisfy is
that of the bend
radius within the production casing (or within the casing and ported casing
collar), along the
whipstock face, at the point of a desired casing exit. In addition, the coiled
tubing-based
conveyance of these synergetic internal/external systems provides for
simultaneous running of
other conventional coiled tubing tools in the same tool string. These may
include a packer, a
mud motor, a downhole (external) tractor, logging tools, and/or a retrievable
bridge plug residing
below the whipstock member.
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[0054] Additional details concerning operation of the internal and external
systems,
including the guidance system (including the use of actuator wires at the end
of the jetting hose
and a geo-spatial chip in the body of the jetting nozzle), are provided in co-
owned U.S. Patent
No. 9,976,351 entitled "Downhole Hydraulic Jetting Assembly." The '351 patent
is incorporated
herein by reference in its entirety.
[0055] Returning to the method at hand, the method also comprises setting
the whipstock at
a desired first casing exit location along the child wellbore. The face of the
whipstock bends the
jetting hose substantially across the entire inner diameter of the wellbore
while the jetting hose
is translated out of the jetting hose carrier.
[0056] The method additionally includes translating the jetting hose out of
the jetting hose
carrier to advance the jetting nozzle against the face of the whipstock, then
directly opposite a
point where it is desired to generate a casing exit, or to exit the casing
through a pre-formed port
in a casing collar.
[0057] The method also includes further advancing the jetting nozzle
through a first window
(which may include an aligned casing collar port) at the first casing exit
location and into the
pay zone. The method then includes further injecting the jetting fluid while
further translating
the jetting hose and connected jetting nozzle through the jetting hose carrier
and along the face
of the whipstock. In this way, a first lateral borehole that extends from the
horizontal wellbore
and out into the pay zone is formed.
[0058] In one aspect, the method of the present invention additionally
includes controlling (i)
a distance of the first lateral borehole from the child wellbore, (ii) a
direction of the first lateral
borehole from the child wellbore, or (iii) both, to avoid a frac hit with the
parent wellbore. In one
aspect, avoiding a frac hit means that the lateral borehole does not intercept
a fracture network or
SRV associated with the parent wellbore. More preferably, avoiding a frac hit
means that the
lateral borehole is oriented in such a way that a subsequent hydraulic
fracturing stage will not
likely create fluid communication (a pressure hit or a frac hit) with the
parent wellbore.
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[0059] In another aspect, the method may include (iv) producing reservoir
fluids from the first
lateral borehole into the child wellbore. This would be for the purpose of
weakening the rock
matrix surrounding the lateral borehole prior to hydraulic fracturing, thereby
creating a new path-
of-least-resistance from which to propagate SRV. Note that multiple lateral
boreholes may be
generated, with various combinations of these four controls, prior to their
receiving a single frac
stage.
[0060] In one embodiment, the method further comprises monitoring wellbore
pressure within
the parent wellbore while pumping fracturing fluids into the first lateral
borehole of the child
wellbore in a designated frac stage. "Wellbore pressure" may mean pressure
within the production
tubing string of the parent wellbore (particularly if it is completed with a
downhole packer), or
may mean pressure within a tubing-casing annulus. Parent well pressure may be
measured in real-
time during the child well frac operation either via surface pressure gauges,
acoustic fluid level
measurements in the tubing-casing annulus, or with downhole gauges.
[0061] The parent's wellbore pressure is monitored to see if a so-called
pressure hit is taking
place in the parent wellbore. Thus, upon detecting a pressure hit within the
parent wellbore, the
operator may discontinue the pumping of j etting fluids into the child
wellbore. Alternatively, the
operator may re-direct the jetting nozzle to change a course of the first
lateral borehole to access
otherwise stranded hydrocarbon reserves
[0062] In one embodiment, the operator may determine an orientation of the
face of the
whipstock once the whipstock is set at the first casing exit location along
the child wellbore. The
operator may change an orientation of the whipstock before hydraulically
jetting a second lateral
borehole. Alternatively, the operator may partially withdraw the jetting hose
and connected jetting
nozzle from the second lateral borehole, and then form a side borehole off of
the second lateral
borehole in a direction away from the parent wellbore to either: (a) avoid a
frac hit in the parent
well; or (b) to generate SRV in a volume of the pay zone that would otherwise
have stranded
reserves; or (c) both.
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[0063] During the fracturing of a lateral borehole, the operator may
monitor micro-seismic
data and/or tiltmeter data in the hydrocarbon producing field. In response to
receiving this data,
optionally coupled with pressure data from the parent wellbore, the operator
may discontinue the
pumping of fracturing fluids into the first lateral borehole.
[0064] In one aspect, the first casing exit location comprises a casing
sleeve placed along a
string of production casing within the wellbore. The casing sleeve comprises
an outer sleeve that
self-orients, then is locked into a stationary position, and having at least
one portal, and an inner
sleeve also having at least one portal. The method then further comprises
mechanically rotating
the inner sleeve to align the at least one portal in the inner sleeve with the
at least one portal in the
outer sleeve, thereby forming the first window. Mechanically rotating the
inner sleeve may
comprise latching a pin along the whipstock into a matching groove within the
inner sleeve, and
then rotating the whipstock.
[0065] In one aspect, the method may further comprise the steps of:
retracting the jetting hose and connected nozzle from the first window;
re-orienting the whipstock at the desired first location;
injecting hydraulic jetting fluid through the jetting hose and connected
nozzle,
thereby forming a second window at the first casing exit location;
advancing the jetting nozzle against the face of the whipstock while injecting
hydraulic jetting fluid through the jetting hose and connected jetting nozzle;
advancing the jetting nozzle through a first window at the first casing exit
location
and into the pay zone; and
further injecting the jetting fluid while advancing the jetting hose and
connected
nozzle along the face of the whipstock, thereby forming a second lateral
borehole that extends
from the second window through a rock matrix in the pay zone.
[0066] The geometry of the second lateral borehole is controlled such that
(i) a distance of the
second lateral borehole from the child wellbore, (ii) a direction of the
second lateral borehole from
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the child wellbore, or (iii) both, will avoid a frac hit with the parent
wellbore during a subsequent
injection of formation fracturing fluids into the second lateral borehole.
[0067] In this embodiment, one or both of the "windows" referenced above
may actually be
the aligned ports in a casing collar. Also in this embodiment, the child
wellbore is preferably a
horizontal wellbore, and the first casing exit location is preferably along
the horizontal leg. In
addition, the second lateral borehole is preferably offset from the first
lateral borehole by between
10-degrees and 350-degrees. In any instance, the jetting fluid typically
comprises abrasive solid
particles, particularly when windows must be formed erosionally through the
casing.
[0068] In another embodiment of the method herein, the method may further
comprise:
retracting the jetting hose and connected nozzle from the first window;
moving the whipstock to a desired second casing exit location along the child
wellbore, and setting the whipstock;
injecting hydraulic jetting fluid through the jetting hose and connected
nozzle;
advancing the jetting nozzle against the face of the whipstock while injecting
hydraulic jetting fluid through the jetting hose and connected jetting nozzle;
advancing the jetting nozzle through the second window at the second casing
exit
location and into the pay zone;
further injecting the jetting fluid while translating the jetting hose and
connected
jetting nozzle along the face of the whipstock, thereby forming a second
lateral borehole that
extends from the second window through the rock matrix in the pay zone; and
controlling (i) a distance of the second lateral borehole from the child
wellbore, (ii) a
direction of the second lateral borehole from the child wellbore, or (iii)
both, to avoid a frac hit
with the parent wellbore during a subsequent fracturing operation.
[0069] Once again, the child wellbore is preferably a horizontal wellbore,
and the first casing
exit location is preferably along the horizontal leg. The first and second
casing exit locations
are each along a horizontal leg of the horizontal wellbore. In addition, the
second casing exit
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location is preferably separated from the first casing exit location by 15 to
200 feet. Preferably,
each of the first and second lateral boreholes is at least 25 feet in length
and, more preferably, at
least 100 feet in length. In any instance, the jetting fluid typically
comprises abrasive solid
particles while jetting through the casing and cement. The operator may then
produce reservoir
fluids from the first and/or the second lateral boreholes.
[0070] Prior to and during pumping fracturing fluids into the second
lateral borehole, the
operator may take pressure data, micro-seismic data and/or tiltmeter data in
the hydrocarbon
producing field from the previous frac stage, and use such data in:
(i) selecting an orientation of the second lateral borehole from the child
wellbore,
(ii) selecting a distance of the second lateral borehole to be formed from the
child
wellbore, or
(iii) both, to avoid a frac hit.
[0071] The process of forming lateral boreholes in such a manner as to
avoid a frac hit during
a subsequent formation fracturing may be done during initial well completion.
Alternatively, the
process may be done after the child wellbore has been producing hydrocarbon
fluids for a period
of time. Alternatively, each lateral borehole may be custom designed based on
data received
during preceding frac stages. In one embodiment, the operator will determine a
distance of the
parent wellbore from the first casing exit location in connection with
avoiding a frac hit.
[0072] During the fracturing of the second lateral borehole, the operator
may again monitor
micro-seismic data and/or tiltmeter data in the hydrocarbon producing field.
In response to
receiving this data, optionally coupled with pressure data from the parent
wellbore, and upon
detecting a pressure hit within the parent wellbore or significant SRV
advancement toward the
parent well, the operator will discontinue the pumping of fracturing fluids
into the second lateral
borehole.
[0073] In one embodiment, the operator may partially withdraw the jetting
hose and connected
jetting nozzle from the second lateral borehole, and then form a side borehole
off of the second
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lateral borehole in a direction away from the parent wellbore to avoid a frac
hit. Avoiding a frac
hit may mean that the side borehole is oriented in such a way that a
subsequent hydraulic fracturing
stage will not likely create fluid communication with the parent wellbore.
[0074] The hydraulic jetting assembly herein is able to generate lateral
bore holes in excess
of 10 feet, or in excess of 25 feet, and even in excess of 300 feet, depending
on the length of the
jetting hose and its jetting hose carrier. Length of penetration and
penetration rate itself may
also be influenced by the hydraulic jetting-resistance qualities of the rock
matrix, or "host rock."
These jetting-resistance qualities may include compressive strength, pore
pressure, cementation,
and other features inherent to the lithology of the host rock matrix. In any
instance, the lateral
boreholes may have a diameter of about 1.0" or greater and may be formed at
penetration rates
much higher than any of the systems that have preceded it that have in common
completing a
90 turn of the jetting hose within the production casing.
[0075] The present system will have the capacity to generate lateral
boreholes from portions
of horizontal and highly directional wellbores heretofore thought unreachable.
Anywhere to
which conventional coiled tubing can be tractored within a cased wellbore,
lateral boreholes can
now be hydraulically jetted. Similarly, superior efficiencies will be captured
as multiple
intervals of lateral boreholes are formed from a single trip. Wherever
satisfactory fracturing
hydraulics (pump rates and pressures) are attainable via the coiled tubing-
casing annulus, the
entire horizontal leg of a newly drilled well may be "perforated and
fractured" in stages without
need of frac plugs, sliding sleeves or dropped balls.
[0076] In one embodiment, multiple lateral boreholes and, optionally, side
mini-lateral
boreholes, together form a network or cluster of ultra-deep perforations in
the rock matrix. Such
a network may be designed by the operator to optimally create SRV and thereby
drain a pay
zone. Preferably, the lateral boreholes extend away from the child wellbore at
or near the plane
of maximum in situ horizontal stress (0-H) within the host pay zone; i.e., in
the same vertical
plane direction that subsequent hydraulic fracks should propagate. It is
preferred that the
longitudinal axis of the child wellbore runs at-or-near normal, or at a right
angle, to GH; that is,
parallel to the plane of minimum in situ horizontal stress (in) within the
host rock. Such a child
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wellbore orientation provides for the trajectory of the jetting nozzle and
hose, after an
approximate 90 turn along the face of the whipstock and immediately upon
exiting the child
wellbore's casing (or casing sleeve), to be in approximate alignment with (TH.
[0077] Various angles may be used for the mini-lateral boreholes to take
advantage of the
richest portions of a pay zone while avoiding frac hits with neighboring
wellbores. Where
multiple lateral boreholes are formed at different orientations from the child
wellbore extending
into different depths, hydrocarbons may be produced from a network of lateral
boreholes.
Moreover, the operator may choose to conduct subsequent formation fracturing
(or other
treating) operations from the lateral boreholes, thereby further extending the
Stimulated
Reservoir Volume ("SRV").
[0078] In one aspect, geometries of lateral boreholes and side mini-lateral
boreholes are
customized within the host pay zone. The boreholes can then optimally receive
a subsequent
stimulation (particularly, hydraulic fracturing) treatments. This, in turn,
enables optimization of
the resultant "SRV" to be obtained from each pumping stage. During fracturing,
the operator
may receive real-time geophysical data, such as micro-seismic, tiltmeter,
and/or ambient micro-
seismic data, indicative of the effectiveness of formation treatments and SRV
development. In
one aspect, during a horizontal wellbore's completion or re-completion, real-
time customization
of the next cluster's lateral borehole geometries may be conducted prior to
pumping a next stage.
[0079] In a variation, the method comprises:
- using hydraulic jetting to form casing exits along the horizontal
wellbore in
sequential stages, or utilizing ported casing collars as pre-formed casing
exits;
- utilizing hydraulic jetting to form mini-lateral boreholes from each
casing exit in
the designated lengths (up to a maximum length equal to that of the jetting
hose)
and trajectories into the surrounding rock matrix;
- hydraulically fracturing the rock matrix along the horizontal wellbore
through the
casing exit;
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- optionally, prior to hydraulically fracturing the rock matrix
through the casing exit,
producing reservoir fluids from the rock matrix, through the mini-lateral
borehole
for a period of time in order to weaken the rock matrix thus biasing a
trajectory of
fractures.
[0080] In any of the above embodiments, the method may further comprise
injecting
fracturing fluids through an annulus formed between the jetting assembly and
the surrounding
production casing, and injecting the fracturing fluids into one or more
lateral boreholes at
injection pressures sufficient to: (1) initially part the rock matrix in the
pay zone; and, (2)
continue propagating the fracture(s), or network of fractures; and typically,
(3) deliver and place
proppant(s), often of various sieve sizes and concentrations throughout the
frac slurry, in order
to "prop-open" the fracture, or network of fractures (whether created or pre-
existing), thus
creating a Stimulated Reservoir Volume ("SRV") that is hydraulically connected
to the wellbore.
[0081] Alternatively or in addition, an acid treatment may be washed down
through the
annular region and into the lateral boreholes, preferably prior to fracturing.
Given the system's
ability to controllably "steer" a jetting nozzle and thereby contour the path
of a lateral borehole
(or, "clusters" of boreholes), fracturing fluids can be more optimally
"guided" and constrained
within a pay zone. Note that, particularly in rocks having a significant
carbonaceous component
to their matrix that is satisfactorily reactive to low-pH fluids, this
hydraulic connection of SRV
to the wellbore may be achieved with acidic stimulation fluids, either with or
without
accompanying proppants.
[0082] In any of the above methods, the translation force used in moving
the jetting hose out
of the jetting hose carrier may be a hydraulic force. The jetting hose and
associated jetting hose
carrier are preferably each at least 10 feet in length and, more preferably,
at least 50 feet in
length.
[0083] In one arrangement, the method further comprises
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- obtaining geo-mechanical data for the pay zone, the data comprising
porosity,
permeability, Poisson ratio, modulus of elasticity, shear modulus, Lame'
constant,
Vp/Vs, or combinations thereof;
- conducting a geo-mechanical analysis of the rock matrix in the pay zone
to
determine a direction of least principle stress; and
- forming at least two lateral boreholes in the pay zone using the downhole
hydraulic
jetting assembly by steering the nozzle (i) in a direction perpendicular to
the
direction of least minimum principle stress, or (ii) in a direction parallel
to the
direction of least minimum principle stress.
[0084] A separate method of completing a wellbore in a hydrocarbon-bearing
pay zone is
also provided herein. In one aspect, the method first comprises hydraulically
jetting a lateral
borehole from a horizontal wellbore. The lateral borehole is formed using a
jetting nozzle and
connected jetting hose. Of interest, the horizontal wellbore and the lateral
borehole are each
formed along a plane in a rock matrix of the pay zone of least principle
stress.
[0085] The method also includes producing hydrocarbon fluids from the pay
zone for a
designated period of time. The result of this period of production is that the
rock matrix is
weakened.
[0086] After the designated period of time, the method includes injecting
fracturing fluids
into the horizontal wellbore and into the lateral borehole. In this step, a
pumping pressure of the
fracturing fluids initially exceeds a fracture initiation pressure of the pay
zone, and subsequently
exceeds a fracture propagation pressure of the pay zone.
[0087] The method then includes forming a vertical plane of weakness
intersecting the
lateral borehole such that a preferred initial path for the fracturing fluids
is created along a
longitudinal axis of the lateral borehole. In other words, a vertical fracture
plane is formed.
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[0088] In this method, it is preferred that a longitudinal axis of the
horizontal wellbore runs
parallel to a direction of the pay zone's least principal horizontal stress.
Similarly, the
longitudinal axis of the lateral borehole runs perpendicular to the horizontal
wellbore, and
accordingly runs parallel to a direction of the pay zone's maximum principal
horizontal stress.
[0089] It is preferred that the jetting hose comprises at least three
electrical power wires
extending along its length. At least three longitudinally oriented actuator
wires receive current
from a corresponding electrical power wire. The actuator wires are connected
at a distal end of
the jetting hose, with the actuator wires being equi-distantly spaced about a
circumference of the
jetting hose. The actuator wires are configured to contract in response to the
electrical current,
whereby differing amounts of electrical current directed through the actuator
wires will induce
a bending moment to orient the jetting nozzle.
[0090] In one aspect, the method further comprises controlling (i) a
distance of the lateral
borehole from the child wellbore away from the parent wellbore, (ii) a
direction of the first lateral
borehole from the child wellbore away from the parent wellbore, or (iii) both,
in order to avoid
a frac hit, wherein the fracturing fluid injected into the child wellbore
reaches: (A) a near-
wellbore vicinity of a parent wellbore; or proceeds even further to, (B) the
parent wellbore itself.
[0091] In another aspect, the method further includes monitoring tubing,
tubing-casing
annulus, and casing-casing annuli pressures within the parent wellbore while
injecting the
hydraulic fracturing fluid into the child wellbore. Upon detecting a pressure
hit within the parent
wellbore, the operator will discontinue pumping the hydraulic fracturing fluid
into the child
wellbore.
[0092] In a related embodiment, the method may further comprise conducting
micro-seismic
monitoring while injecting jetting fluid into the jetting hose to form the
lateral borehole in the
child wellbore, thereby generating micro-seismic data. In connection with this
step, the operator
may calibrate the micro-seismic data to a known depth and geospatial
coordinates of the jetting
nozzle. Alternatively or in addition, micro-seismic monitoring may be
conducted while forming
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the vertical fracture plane. Upon detecting fracture propagation from the
lateral borehole into
the near-wellbore vicinity of the parent wellbore, the operator may:
(i) discontinue the pumping of fracturing fluid into the child wellbore;
(ii) relocate the jetting hose along the horizontal wellbore to prepare for
placement
of the a next frac stage based upon an interpretation of the micro-seismic
data; and
(iii) configure respective depths and directions for additional lateral
boreholes in a
next frac stage based upon the micro-seismic data associated with the first
lateral borehole;
in order to maximize Stimulated Reservoir Volume ("SRV") for the next frac
stage while
avoiding a frac hit in the parent wellbore.
Brief Description of the Drawings
[0093] So that the manner in which the present inventions can be better
understood, certain
illustrations, charts and/or flow charts are appended hereto. It is to be
noted, however, that the
drawings illustrate only selected embodiments of the inventions and are
therefore not to be
considered limiting of scope, for the inventions may admit to other equally
effective
embodiments and applications.
[0094] Figure 1A is a cross-sectional view of an illustrative horizontal
wellbore. Half-
fracture planes are shown in 3-D along a horizontal leg of the wellbore to
illustrate fracture stages
and fracture orientation relative to a subsurface formation.
[0095] Figure 1B is an enlarged view of the horizontal portion of the
wellbore of Figure 1A.
Conventional perforations are replaced by ultra-deep perforations ("UDP' s"),
or mini-lateral
boreholes, that are subsequently fracked to create fracture planes.
[0096] Figure 2 is a longitudinal, cross-sectional view of a downhole
hydraulic jetting
assembly of the present invention, in one embodiment. The assembly is shown
within a
horizontal section of a production casing. The jetting assembly has an
external system and an
internal system.
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[0097] Figure 3A is a longitudinal, cross-sectional view of the internal
system of the
hydraulic jetting assembly of Figure 2. The internal system extends from an
upstream battery
pack end cap (that mates with the external system's docking station) at its
proximal end to an
elongated hose having a jetting nozzle at its distal end.
[0098] Figure 3B is an expanded cross-sectional view of the terminal end of
the jetting hose
of Figure 3A, showing the jetting nozzle of the internal system. The bend
radius of the jetting
hose "R" is shown within a cut-away section of the whipstock of the external
system of Figure
3.
[0099] Figure 4 is a longitudinal, cross-sectional view of the external
system of the downhole
hydraulic jetting assembly of Figure 2, in one embodiment. The external system
resides within
production casing of the horizontal leg of the wellbore of Figure 2.
[00100] Figure 4A is an enlarged, longitudinal cross-sectional view of a
portion of a bundled
coiled tubing conveyance medium which conveys the external system of Figure 4
into and out
of the wellbore.
[00101] Figure 4A- 1 a is an axial, cross-sectional view of the coiled
tubing conveyance
medium of Figure 4A-1. In this embodiment, an inner coiled tubing is "bundled"
concentrically
with both electrical wires and data cables within a protective outer layer.
[00102] Figures 4A-2 is another axial, cross-sectional view of the coiled
tubing conveyance
medium of Figure 4A-la, but in a different embodiment. Here, the inner coiled
tubing is
"bundled" eccentrically within the protective outer layer to provide more
evenly-spaced
protection of the electrical wires and data cables.
[00103] Figure 4B is a longitudinal, cross-sectional view of a crossover
connection, which is
the upper-most member of the external system of Figure 4. The crossover
section is configured
to join the coiled tubing conveyance medium of Figure 4A to a main control
valve.
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[00104] Figure 4B-la is an enlarged, perspective view of the crossover
connection of Figure
4B, seen between cross-sections E-E' and F-F'. This view highlights the wiring
chamber's
general transition in cross-sectional shape from circular to elliptical.
[00105] Figure 4C is a longitudinal, cross-sectional view of the main
control valve of the
external system of Figure 4.
[00106] Figure 4C-la is a cross-sectional view of the main control valve,
taken across line G-
G' of Figure 4C.
[00107] Figure 4C-lb is a perspective view of a sealing passage cover of
the main control
valve, shown exploded away from Figure 4C-la.
[00108] Figure 4D is a longitudinal, cross-sectional view of selected
portions of the external
system of Figure 4. Visible are a jetting hose pack-off section, and an outer
body transition from
the preceding circular body (I-I') of the jetting hose carrier section to a
star-shaped body (J-J') of
the jetting hose pack-off section
[00109] Figure 4D-la is an enlarged, perspective view of the transition
between lines I-I' and
J-F of Figure 4D.
[00110] Figure 4D-2 shows an enlarged view of a portion of the jetting hose
pack-off section.
Internal seals of the pack-off section conform to the outer circumference of
the jetting hose
residing therein. A pressure regulator valve is shown schematically adjacent
the pack-off
section.
[00111] Figure 4E is a cross-sectional view of a whipstock member of the
external system of
Figure 4, but shown vertically instead of horizontally. The jetting hose of
the internal system is
shown bending across the whipstock, and extending through a window in the
production casing.
The jetting nozzle of the internal system is shown affixed to the distal end
of the jetting hose.
[00112] Figure 4E-la is an axial, cross-sectional view of the whipstock
member, with a
perspective view of sequential axial jetting hose cross-sections depicting its
path downstream
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from the center of the whipstock member taken across line 0-0' of Figure 4E to
the start of the
jetting hose's bend radius as it approaches line P-P'.
[00113] Figure 4E-lb depicts an axial, cross-sectional view of the
whipstock member taken
across line P-P' of Figure 4E.
[00114] Figure 4MW is a longitudinal cross-sectional view of a modified
whipstock designed
to be mateably received within a ported casing collar. Translational and
rotational movement of
the modified whipstock actuates movement of an inner sleeve of the ported
casing collar,
providing a pre-formed casing exit.
[00115] Figure 4MW.1 is an exploded view of the modified whipstock wherein
a jetting hose
exit is aligned with portals of inner and outer sleeves of the casing collar.
[00116] Figure 4MW.2 is an enlarged view of the whipstock of Figure 4MW.1.
Here, the
whipstock is rotated 90 about a longitudinal access, revealing a pair of
opposing "shift dogs."
[00117] Figure 4MW.2.SD is an exploded, cross-sectional view of one of the
two spring-
loaded shift dogs.
[00118] Figure 4MW.2.AB is an exploded, cross-sectional view of a portion
of one of the
spring-loaded alignment blocks of Figure 4MW.
[00119] Figure 4PCC.1 is a longitudinal cross-sectional view of the ported
casing collar of
Figure 4MW.
[00120] Figure 4PCC.1.SDG is an exploded, longitudinal cross-sectional view
of a shift dog
groove that resides in the ported casing collar of Figure 4PCC.1. The shift
dog groove is
dimensioned to receive the shift dogs of the modified whipstock.
[00121] Figure 4PCC.1.CLD is an exploded cross-sectional view of a collet
latch dog of the
ported casing collar of Figure 4PCC.1.
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[00122] Figure 4PCC.1.CSP is a two-dimensional "roll-out" view of a control
slot pattern for
the inner sleeve of the ported casing collar, showing each of five possible
slot positions.
[00123] Figure 4PCC.2 is an operational series showing the relative
positions of each of the
outer sleeve's two stationary portals versus each of the inner sleeve's three
portals as the inner
sleeve is translated and rotated into each of its five possible positions.
[00124] Figure 4PCC.3d is a series of perspective views of the ported
casing collar of Figure
4PCC.1. Figure 4PCC.3d illustrates positions of the ported casing collar when
placed along a
production casing string per the control slot positions of Figure 4PCC.2.
[00125] Figure 4PCC.3d.1 shows the ported casing collar in a position where
the inner sleeve
portals and the outer sleeve portals are out of alignment. This is a "closed"
position.
[00126] Figure 4PCC.3d.2 shows an alignment of certain inner sleeve portals
with certain
outer sleeve portals where "east" ports are open.
[00127] Figure 4PCC.3d.3 shows an alignment of certain inner sleeve portals
with certain
outer sleeve portals where "west" ports are open.
[00128] Figure 4PCC.3d.4 shows an alignment of certain inner sleeve portals
with certain
outer sleeve portals where both the "east" and the "west" ports are open.
[00129] Figure 4PCC.3d.5 again shows the inner sleeve portals and the outer
sleeve portals
out of alignment. This is another closed position.
[00130] Figure 4HLS is a longitudinal, cross-sectional view of a hydraulic
locking swivel as
may be placed at each end of the ported casing collar of Figure 4PCC.3d.
[00131] Figure 5A is a perspective view of a hydrocarbon-producing field.
In this view, a
child wellbore is being completed adjacent to a parent wellbore. Depletion in
a pay zone
surrounding the parent wellbore attracts a frac hit while pumping frac stage
"n" during
completion of the child.
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[00132] Figure 5B is another perspective view of the hydrocarbon-producing
field of Figure
5A. Additional frac stages are shown from the child wellbore.
Detailed Description of Certain Embodiments
Definitions
[00133] As used herein, the term "hydrocarbon" refers to an organic
compound that includes
primarily, if not exclusively, the elements hydrogen and carbon. Examples of
hydrocarbon-
containing materials include any form of natural gas, oil, coal, and bitumen
that can be used as
a fuel or upgraded into a fuel.
[00134] As used herein, the term "fluid" refers to gases, liquids, and
combinations of gases
and liquids, as well as to combinations of gases and solids, and combinations
of liquids and
solids.
[00135] As used herein, the term "hydrocarbon fluids" refers to a
hydrocarbon or mixtures of
hydrocarbons that are gases or liquids at formation conditions, at processing
conditions, or at
ambient conditions. Examples include oil, natural gas, condensate, coal bed
methane, shale oil,
shale gas, and other hydrocarbons that are in a gaseous or liquid state.
[00136] As used herein, the term "subsurface" refers to geologic strata
occurring below the
earth's surface.
[00137] The term "subsurface interval" refers to a formation or a portion
of a formation
wherein formation fluids may reside. The fluids may be, for example,
hydrocarbon liquids,
hydrocarbon gases, aqueous fluids, or combinations thereof.
[00138] The terms "zone" or "zone of interest" refer to a portion of a
formation containing
hydrocarbons. Sometimes, the terms "target zone," "pay zone," "reservoir", or
"interval" may
be used.
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[00139] The term "borehole" as used herein refers to the excavated void
space in the
subsurface, typically of circular cross-section and generated by excavation
mechanisms; for
example, of either drilling or jetting. A borehole may have almost any
longitudinal azimuth or
orientation, and may be up to hundreds (jetting) or more typically thousands
or tens of thousands
of feet in length (drilling).
[00140] As used herein, the term "wellbore" refers to a borehole excavated
by drilling and
subsequently cased (typically with steel casing) along much if not its entire
length. Usually at
least 3 or more concentric strings of casing are required to form a wellbore
for the production of
hydrocarbons. Each casing is typically cemented within the borehole along a
significant
portion(s) of its length, with the cementing of the larger diameter, shallower
strings requiring
circulation to surface. As used herein, the term "well" may be used
interchangeably with the
term "wellbore."
[00141] The term "jetting fluid" refers to any fluid pumped through a
jetting hose and nozzle
assembly for the purpose of erosionally boring a lateral borehole from an
existing wellbore. The
jetting fluid may or may not contain an abrasive material.
[00142] The term "abrasive material" or "abrasives" refers to small, solid
particles mixed with
or suspended in the jetting fluid to enhance the erosional degradation of the
target by the (jetting)
liquid by adding to it destruction of the target face via the solid impact
force(s) of the abrasive.
Targets typically referenced herein are: (1) the pay zone; and/or (2) the
cement sheath between
the production casing and pay zone; and/or (3) the wall of the production
casing at the point of
desired casing exit.
[00143] The terms "tubular" or "tubular member" refer to any pipe, such as
a joint of casing,
a portion of a liner, a joint of tubing, a pup joint, or coiled tubing.
[00144] The terms "lateral borehole" or "mini-lateral" or "ultra-deep
perforation" ("UDP")
refer to the resultant borehole in a subsurface formation, typically upon
exiting a production
casing and its surrounding cement sheath in a child wellbore, with the
borehole being formed in
a pay zone. For the purposes herein, a UDP is formed as a result of hydraulic
jetting forces
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erosionally boring through the pay zone with a high pressure jetting fluid
directed through a
jetting hose and out a jetting nozzle affixed to the terminal end of the
jetting hose.
[00145] The terms "steerable" or "guidable", as applied to a hydraulic
jetting assembly, refers
to a portion of the jetting assembly (typically, the jetting nozzle and/or the
portion ofjetting hose
immediately proximal the nozzle) for which an operator can direct and control
its geo-spatial
orientation while the jetting assembly is in operation. This ability to
direct, and subsequently re-
direct the orientation of the jetting assembly during the course of erosional
excavation can yield
UDP' s with directional components in one, two, or three dimensions, as
desired.
[00146] The term "perforation cluster" refers to a group of conventional
perforations, and/or
sliding sleeve ports generally proximal to one another in a common wellbore. A
given
perforation cluster is generally hydraulically fracture stimulated with a
common frac "stage,"
typically with the intent of creating a single contiguous Stimulated Reservoir
Volume ("SRV")
within the pay zone. In this disclosure, a "cluster" may be used to refer to
two or more lateral
boreholes formed at a single casing exit location for a frac stage.
[00147] The term "stage" references a discreet portion of a stimulation
treatment applied in
completing or recompleting a specific pay zone, or specific portion of a pay
zone. In the case of
a cased horizontal child wellbore, up to 10, 20, 50 or more stages may be
applied to their
respective perforation borehole clusters. Typically, this requires some form
of zonal isolation
prior to pumping each stage.
[00148] The terms "contour" or "contouring" as applied to individual UDP's,
or groupings of
UDP' s in a "cluster", refers to steerably excavating the lateral borehole so
as to optimally
receive, direct, and control stimulation fluids, or fluids and proppants, of a
given stimulation
(typically, fracking) stage. The result is an optimized Stimulated Reservoir
Volume ("SRV").
[00149] The terms "real time" or "real time analysis" of geophysical data
(such as micro-
seismic, tiltmeter, and or ambient micro-seismic data) and/or pressure data
(such as obtained
from pressure "bombs") that is obtained during the course of pumping a stage
of a stimulation
(such as fracking) treatment means that results of said data analysis can be
applied to: (1) altering
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the remaining portion of the stimulation treatment (yet to be pumped) in its
pump rates, treating
pressures, fluid rheology, and proppant concentration in order to optimize the
benefits therefrom;
and, (2) optimizing the placement of perforations, or contouring the
trajectories of UDP' s, within
the subsequent "cluster(s)" to optimize the SRV obtained from the subsequent
stimulation stages.
[00150] The term "parent wellbore" refers to a wellbore that has already
been completed in
and is producing reservoir fluids from a pay zone for a period of time,
creating an area of pressure
depletion within the pay zone. A "parent" wellbore may be a vertical,
horizontal, or directional
well.
[00151] The term "child wellbore" refers to a well being completed in a
common pay zone
proximal an offsetting "parent" wellbore.
[00152] The term "frac hit" describes an interwell communication event
wherein a "parent"
well is affected by the pumping of a hydraulic fracturing treatment in a new
"child" well. A frac
hit from a single child well can hit more than one parent well.
[00153] The term "jetting hose" refers to a flexible fluid conduit, capable
of conducting
relatively small volumes of fluids at relatively high pressures, typically up
to thousands of psi.
Description of Specific Embodiments
[00154] A method of stimulating a subsurface formation is provided herein.
Specifically, a
method of stimulating a formation, such as through hydraulic fracturing, is
provided wherein a
so-called "frac hit" of a neighboring wellbore is avoided or wherein an
otherwise stranded
portion of a reservoir is accessed.
[00155] The method employs a novel downhole hydraulic jetting assembly as
disclosed in co-
owned U.S. Patent No. 9, 976,351 entitled "Downhole Hydraulic Jetting
Assembly." This
assembly allows an operator to run a jetting hose into the horizontal section
of a wellbore, and
then "push" the jetting hose out of a tubular jetting hose carrier using
hydraulic forces.
Beneficially, the jetting hose is extruded out of the jetting hose carrier and
against the concave
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face of a whipstock, whereupon jetting fluids may be injected through the
jetting hose and a
connected nozzle. A mini-lateral borehole may then be formed extending from
the wellbore.
[00156] In accordance with industry procedures, a hydraulic fracturing (or
other formation
treating procedure) is conducted in the horizontally formed wellbore. In this
instance, fracing is
conducted by injecting fracturing fluids into the lateral borehole. In the
present method, wellbore
pressure in an offset well is monitored during the fracing stage. In the event
pressures indicative
of an impending frac hit are detected, the pumping of fracturing fluids into
the lateral borehole
is discontinued.
[00157] In one aspect of the present method, a specially-designed whipstock
of the jetting
assembly is provided. The whipstock is designed to be mateably received by a
novel ported
casing collar, which is also provided herein. The whipstock may be manipulated
at the surface
to selectively align portals within the casing collar, thereby creating casing
windows, or "casing
exits," through which the jetting nozzle and connected hydraulic hose may
pass. One or more
boreholes may then be "jetted" outwardly into a surrounding subsurface
formation through the
aligned portals.
[00158] The lateral boreholes essentially represent ultra-deep perforations
("UDP's") that are
formed by using hydraulic forces directed through a flexible, high pressure
jetting hose. Both
the trajectory and the length of the borehole may be controlled. Using the
downhole assembly,
the operator is able to use a single hose and nozzle to jet a series of
lateral boreholes within the
leg of a horizontal wellb ore in a single trip.
[00159] Figure 1A is a schematic depiction of a horizontal well 4. A
wellhead 5 is located
above the well 4 at an earth's surface 1. The well 4 penetrates through a
series of subsurface
strata 2a through 2h before reaching a pay zone 3. The well 4 includes a
horizontal section 4c.
The horizontal section 4c is depicted between a "heel" 4b and a "toe" 4d.
[00160] Conventional perforations 15 within the production casing 12 are
shown in up-and-
down pairs. The perforations 15 are depicted with subsequent hydraulic
fracture half-planes (or,
"frac wings") 16.
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[00161] Figure 1B is an enlarged view of the lower portion of the well 4 of
Figure 1A. Here,
the horizontal section 4c between the heel 4b and the toe 4d is more clearly
seen. In this
depiction, application of the subject apparati and methods herein replaces the
conventional
perforations (15 in Figure 1A) with pairs of opposing lateral boreholes 15 Of
interest, the lateral
boreholes include subsequently generated fracture half-planes 16. In the view
of Figure 1B, the
frac wings 16 are now better confined within the pay zone 3, while reaching
much further out
from the horizontal wellbore 4c into the pay zone 3. Stated another way, in-
zone fracture
propagation is enhanced by the pre-formed UDP's 15, forming an enhanced
Stimulated
Reservoir Volume, or "SRV."
[00162] Figure 2 provides a longitudinal, cross-sectional view of a
downhole hydraulic
jetting assembly 50, in one embodiment. The jetting assembly 50 is shown
residing within a
string of production casing 12. The production casing 12 may have, for
example, a 4.5-inch
O.D. (4.0-inch ID.). The production casing 12 is presented along a horizontal
portion 4c of the
wellbore 4. As noted in connection with Figures 1A and 1B, the horizontal
portion 4c defines
a heel 4b and a toe 4d.
[00163] The jetting assembly 50 generally includes an internal system 1500
and an external
system 2000. The jetting assembly 50 is designed to be run into a wellbore 4
at the end of a
working string, sometimes referred to herein as a "conveyance medium."
Preferably, the
working string is a string of coiled tubing, or more preferably, coiled tubing
with electric line
("e-coil") 100. Alternatively, a "bundled" product that incorporates
electrically conductive
wiring and data conductive cables (such as fiber optic cables) around the
coiled tubing core may
be used.
[00164] It is preferred to maintain an outer diameter of the coiled tubing
100 that leaves an
annular area within the approximate 4.0" I.D. of the casing 12 that is greater
than or equal to the
cross-sectional area open to flow for a 3.5" O.D. frac (tubing) string. This
is because, in the
preferred method (after jetting one or more, preferably two opposing mini-
laterals, or even
specially contoured "clusters" of small-diameter lateral boreholes), fracture
stimulation can
immediately (after repositioning the tool string slightly downhole) take place
down the annulus
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between the coiled tubing 100 plus the external system 2000, and the well
casing 12. For 9.2#,
3.5" O.D. tubing (i.e., frac string equivalent), the ID. is 2.992 inches, and
the cross-sectional
area open to flow is 7.0309 square inches. Back-calculating from this same
7.0309 in2
equivalency yields a maximum O.D. available for both the coiled tubing
conveyance medium
100 and the external system 2000 (having generally circular cross-sections) of
2.655". Of
course, a smaller O.D. for either may be used provided such accommodate a
jetting hose 1595.
[00165] In the view of Figure 2, the assembly 50 is in an operating
position, with a jetting
hose 1595 being run through a whipstock 1000, and a jetting nozzle 1600
passing through a first
window "W" of the production casing 12. The jetting hose 1595 will preferably
have a core that
is fluid impermeable and that has a low friction resistance to the flowing
fluid. Suitable core
materials include PTFE (or "Teflon "). The jetting hose 1595 will also have
one or more layers
of reinforcement surrounding the core, such as spiral or braided steel wire or
braided Kevlar.
Finally, a cover or shroud is placed around the reinforcement layer.
[00166] The nozzle 1600 may be any known jetting nozzle, including those
described in the
'351 patent, useful for jetting through casing, cement and a rock formation.
However, it is
preferred that a unique, electric-driven, rotatable "fan jet" jetting nozzle
be employed as part of
the external system. The nozzle can emulate the hydraulics of conventional
hydraulic
perforators, thereby precluding the need for a separate run with a milling
tool to form a casing
exit. The nozzle optionally includes rearward thrusting jets about the body to
enhance forward
thrust and borehole cleaning during lateral borehole formation, and to provide
clean-out and
borehole expansion during pull-out.
[00167] As an alternative feature, the whipstock 1000 may operate in
conjunction with a novel
casing collar. In this instance, the whipstock 1000 latches into and
manipulates an inner sleeve
of the collar using an extension mechanism (discussed below). In this way,
portals of the inner
sleeve can be selectively aligned with portals of an outer sleeve that has
self-oriented by virtue
of gravitational forces applied to its weighted belly. Hydraulic pressure then
locks the outer
sleeve into this desired orientation, thereby rendering it stationary relative
to the inner sleeve.
The whipstock 1000 can then mateably attach to, and manipulate both
rotationally and
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translationally, the inner sleeve, thereby creating access to pre-fabricated
and pre-oriented casing
exit alternatives.
[00168] In Figure 2, a string of coiled tubing 100 is used as the
conveyance medium for the
downhole hydraulic jetting assembly. The jetting assembly 50 includes an
internal system
(shown in Figure 3A at 1500) and an external system (shown in Figure 4 at
2000). The internal
system 1500 largely resides within the external system 2000 during run-in.
[00169] Near the proximal end of the jetting assembly 50, just downstream
to its connection
to the conveyance medium coiled tubing 100, is a main control valve, indicated
at 300. The
main control valve 300 directs fluids selectively to either: (1) the internal
system 1500, and
specifically to the jetting hose 1595; or, (2) annuli associated with the
external system 2000.
[00170] A jetting hose carrier 400 is shown in Figure 1. The jetting hose
carrier 400 is part
of the external system 2000, and closely holds the jetting hose 1595 during
run-in and pull-out.
A micro-annulus resides between the jetting hose 1595 and the jetting hose
carrier 400. The
micro-annulus is sized to prevent buckling of the jetting hose 1595.
[00171] Crossover sections are shown at 500, 800 and 1200. The crossover
sections 500, 800
are also part of the external system 2000. In addition, a pack-off section 600
and an optional
internal tractor system 700 are provided. The features are described in the
'351 patent.
[00172] At the end of the jetting assembly 50, and below the whipstock
1000, are optional
components. These may include a conventional tractor 1350 and a logging sonde
1400.
[00173] Figure 3A is a longitudinal, cross-sectional view of the internal
system 1500 of the
hydraulic jetting assembly 50 of Figure 2. The internal system 1500 is a
steerable system that,
when in operation, is able to move within and extend out of the external
system 2000. The
internal system 1500 is comprised primarily of:
(1) power and geo-control components;
(2) a jetting fluid intake;
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(3) the jetting hose 1595; and
(4) the jetting nozzle 1600.
[00174] The internal system 1500 is designed to be housed within the
external system 2000
while being conveyed by the coiled tubing 100 and the attached external system
2000 into and
out of the child wellbore 4. Extension of the internal system 1500 from and
retraction back into
the external system 2000 is accomplished by the application of: (a) hydraulic
forces; (b)
mechanical forces; or (c) a combination of hydraulic and mechanical forces.
Beneficial to the
design of the internal 1500 and external 2000 systems comprising the hydraulic
jetting apparatus
50 is that transport, deployment, or retraction of the jetting hose 1595 never
requires the jetting
hose 1595 to be coiled. Specifically, the jetting hose 1595 is never subjected
to a bend radius
smaller than the I.D. of the production casing 12, and that only incrementally
while being
advanced along the whipstock 1050 of the jetting hose whipstock member 1000 of
the external
system 2000. Note the jetting hose 1595 is typically 1/4th" to 5/8ths" ID.,
and up to approximately
1" 0.D., flexible tubing that is capable of withstanding high internal
pressures.
[00175] During jetting, the path of the high pressure hydraulic jetting
fluid is as follows:
(1) Jetting fluid is discharged from a high pressure pump at the surface 1
down the
I.D. of the coiled tubing conveyance medium 100, at the end of which it enters
the external system 2000;
(2) Jetting fluid enters the external system 2000 through a coiled tubing
transition
connection 200;
(3) Jetting fluid enters the main control valve 300 through a jetting fluid
passage;
(4) Because the main control valve 300 is positioned to receive jetting fluid
(as
opposed to hydraulic fluid), a sealing passage cover will be positioned to
seal a
hydraulic fluid passage, leaving the only available fluid path through the
jetting
fluid passage; and
(5) Because of an upper seal assembly 1580 at the top of the jetting hose
carrier
400, which seals a micro-annulus between the jetting hose 1595 and the jetting
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hose carrier 400, jetting fluid cannot go around the jetting hose 1595 (note
this
hydraulic pressure on the seal assembly 1580 is the force that tends to pump
the
internal system 1500, and hence the jetting hose 1595, "down the hole") and
thus jetting fluid is forced to go through the jetting hose 1595.
[00176] Features of the internal system 1500 as depicted in Figure 3A are
also described in
the '351 patent. These include the optional battery pack 1510 with its
upstream and downstream
battery pack end caps 1520 and 1530, the battery pack casing 1540, the
batteries 1551, columnar
supports 1560, a fluid receiving funnel 1570, end caps 1562, 1563, the seal
assembly 1580 and
electrical wires 1590. In addition, a docking station 325 with a conically
shaped end cap 323 is
described in the '351 patent.
[00177] The downward hydraulic pressure of the jetting fluid acting upon
the axial cross-
sectional area of the jetting hose's fluid receiving funnel 1570 creates an
upstream-to-
downstream force that tends to "pump" the seal assembly 1580 and connected
jetting hose 1595
"down the hole." In addition, because the components of the fluid receiving
funnel 1570 and a
supporting upper seal 1580U of the seal assembly 1580 are slightly flexible,
the net pressure
drop described above serves to swell and flare the outer diameters of upper
seal 1580 radially
outwards, thus producing a fluid seal that precludes fluid flow behind the
hose 1595.
[00178] Moving down the hose 1595 to the distal end, Figure 3B provides an
enlarged, cross
sectional view of the end of the jetting hose 1595. Here, the jetting hose
1595 is passing through
the whipstock 1000 along the whipstock face 1050.1. A jetting nozzle 1600 is
attached to the
distal end of the jetting hose 1595. The jetting nozzle 1600 is shown in a
position immediately
subsequent to forming an exit opening, or window "W" in the production casing
12. Of course,
it is understood that the present assembly 50 may be reconfigured for
deployment in an uncased
wellb ore.
[00179] As described in the parent applications, the jetting hose 1595
immediately preceding
this point of casing exit "W" spans the entire I.D. of the production casing
12. In this way, a
bend radius "R" of the jetting hose 1595 is provided that is always equal to
the I.D. of the
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production casing 12. This allows the assembly 50 to utilize the entire casing
(or wellbore) I.D.
as the bend radius "R" for the jetting hose 1595, thereby providing for
utilization of the
maximum I.D./O.D hose. This, in turn, provides for placement of maximum
hydraulic
horsepower ("HHP") at the jetting nozzle 1600, which further translates into
the capacity to
maximize formation jetting results such as penetration rate for the lateral
boreholes.
[00180] It is observed from Figure 3B that there are three "touch points"
for the bend radius
"R" of the jetting hose 1595. First, there is a touch point where the hose
1595 contacts the I.D.
of the casing 12. This occurs at a point directly opposite and slightly
(approximately one casing
I.D. width) above the point of casing exit "W." Second, there is a touch point
along a whipstock
curved face 1050.1 of the whipstock member 1000 itself Finally, there is a
touch point against
the I.D. of the casing 12 at the point of casing exit "W," at least until the
window "W" is formed.
Note these same three touch points may be provided by the arcuate path of the
jetting hose tunnel
3050 within the modified whipstock 3000, discussed later herein.
[00181] Note that this hydraulic horsepower may be utilized in boring
operations via five
distinct modes:
(1) jetting with purely high pressure fluid, such that the boring mechanism is
purely
erosional;
(2) adding to erosion the destruction (boring) mechanism of cavitation, as
with high
pressure fluid discharged from a vortex nozzle, or jetting with a
supercritical gas;
(3) adding an abrasive to the fluid jetting streams of (1) and (2); and
lastly,
(4) boring through the rock target mechanically, via the interface of blades,
teeth, or
"buttons", protruding from the nozzle face such that the destructive force of
the fluid
jets are augmented by mechanical forces expended directly on the rock.
[00182] In any of these cases, an indexing mechanism in the tool string
allows the whipstock
1050 to be oriented in discreet increments radially about the longitudinal
axis of the wellbore.
Once the slips are set, the indexing mechanism utilizes a hydraulically
actuated ratchet-like
action that can rotate an upstream portion of the whipstock 1000 in discreet,
say 5 or 10
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increments. The indexing mechanism is hydraulically actuated, meaning that it
relies upon
pressure pulses to rotate about the wellbore. Optionally, a modified whipstock
3000 may be
rotated electromechanically rotated into the desired position. A gyroscopic /
geospatial device
may be incorporated in the whipstocks 1050 or 3000, or otherwise along the
tool string 50 to
provide a real-time measurement of whipstock orientation. The indexing section
is described in
detail in U.S. Patent No. 9,856,700, which is incorporated herein by reference
in its entirety. In
this way, the whipstock face 1050.1 is set to direct the jetting nozzle 1600
in a desired orientation,
such as away from a neighboring parent wellbore.
[00183] In an alternate embodiment, the hydraulically operated indexing
mechanism is
replaced by an electrically powered motor that rotates the whipstock. Such an
assembly can
include orientation sensors (such as gyroscopic sensors, magnetometers,
accelerometers, or some
combination thereof) that provide a direct, real-time measurement of the
whipstock face 1050.1
orientation. Particularly since the advent of horizontal drilling, this sensor
technology has
become quite robust and commonplace. Such a directional sensor package,
particularly
developed to be extremely compact (1.04" O.D. X 12.3" long) and rated for high
temperatures
(175 C / 347 F) is provided in Applied Physics Systems' Model 850HT High
Temperature,
Small Diameter Directional Sensor package.
[00184] As depicted in Figure 3B (and in Figure 4E), the whipstock 1000 is
in its set and
operating position within the casing 12. (U.S. Patent No. 8,991,522, which is
incorporated herein
by reference, also demonstrates the whipstock member 1050 in its run-in
position.) The actual
whipstock 1050 within the whipstock member 1000 is supported by a lower
whipstock rod 1060.
When the whipstock member 1000 is in its set-and-operating position, the upper
curved face
1050.1 of the whipstock member 1050 itself spans substantially the entire I.D.
of the casing 12.
If, for example, the casing I.D. were to vary slightly larger, this would
obviously not be the case.
The three aforementioned "touch points" of the jetting hose 1595 would remain
the same,
however, albeit while forming a slightly larger bend radius "R" precisely
equal to the (new)
enlarged I.D. of casing 12.
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[00185] Figure 4E is a cross-sectional view of the whipstock member 1000 of
the external
system of Figure 4, but shown vertically instead of horizontally. The jetting
hose 1050 of the
internal system (Figure 3) is shown bending across the whipstock face 1050.1,
and extending
through a window "W" in the production casing 12. The jetting nozzle 1600 of
the internal
system 1500 is shown affixed to the distal end of the jetting hose 1595.
[00186] Figure 4E-la is an axial, cross-sectional view of the whipstock
member 1000, with
a perspective view of sequential axial jetting hose cross-sections depicting
its path downstream
from the center of the whipstock member 1000. This view is taken across line 0-
0' of Figure
4E , and presents sequential views of the jetting hose 1600 from the start of
the bend radius as it
approaches line P-P'.
[00187] Figure 4E-lb depicts an axial, cross-sectional view of the
whipstock member 1000
taken across line P-P' of Figure 4E. Note the adjustments in location and
configuration of both
the whipstock member's wiring chamber and hydraulic fluid chamber from line 0-
0' to line P-
P'.
[00188] In an alternative embodiment (discussed further below in connection
with Figure
4MW), the jetting hose assembly's whipstock 3000 is configured to be mateably
received by a
casing collar 4000 located downhole. The casing collar 4000 is not run in with
the coiled tubing
string 100 and is not part of the assembly 50; instead, the casing collar is
run into the well 4c
with the production casing during completion. In this instance, the whipstock
1050 is a single
body having an integral curved face, and an outer diameter having a pair of
opposing shift dogs
that releasably latch into internal recesses of the casing collar.
[00189] As provided in full detail in the '351 patent, the internal system
1500 enables a
powerful hydraulic nozzle 1600 to jet away subsurface rock in a controlled (or
steerable) manner,
thereby forming a mini-lateral borehole that may extend many feet out into a
formation. The
unique combination of the internal system's jetting fluid receiving funnel
1570, the upper seal
1580U, the jetting hose 1595, in connection with the external system's 2000
pressure regulator
valve 610 and pack-off section 600 (discussed below) provide for a system by
which
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advancement and retraction of the jetting hose 1595, regardless of the
orientation of the wellbore
4, can be accomplished entirely by hydraulic means. Alternatively, mechanical
means may be
added through use of an internal tractor system 700.
[00190] Specifically, "pumping the hose 1595 down-the-hole" has the
following sequence:
(1) the micro-annulus 1595.420 between the jetting hose 1595 and the jetting
hose
carrier's inner conduit 420 is filled by pumping hydraulic fluid through the
main
control valve 310, and then through the pressure regulator valve 610; then
(2) the main control valve 310 is switched electronically using surface
controls to
begin directing jetting fluid to the internal system 1500; which
(3) initiates a hydraulic force against the internal system 1500 directing
jetting fluid
through the intake funnel 1570, into the jetting hose 1595, and "down-the-
hole"; such
force being resisted by
(4) compressing hydraulic fluid in the micro-annulus 1595.420; which is
(5) bled-off, as desired, from surface control of the pressure regulator valve
610,
thereby regulating the rate of "down-the-hole" decent of the internal system
1500.
[00191] Similarly, the internal system 1500 can be pumped back "up-the-
hole" by directing
the pumping of hydraulic fluid through the main control valve 310 and then
through the pressure
regulator valve 610, thereby forcing an ever-increasing volume of hydraulic
fluid into the micro-
annulus 1595.420 between the jetting hose 1595 and the jetting hose conduit
420. The hydraulic
pressure pushes upwardly against the bottom seals 1580L of the jetting hose
seal assembly 1580,
thereby driving the internal system 1500 back "up-the-hole". Thus, hydraulic
forces are
available to assist in both conveyance and retrieval of the jetting hose 1595.
[00192] The Figure 3 series of drawings, and the preceding paragraphs
discussing those
drawings, are directed to the internal system 1500 for the hydraulic jetting
assembly 50. The
internal system 1500 provides a novel system for conveying the jetting hose
1595 into and out
of a child wellbore 4 for the subsequent steerable generation of multiple mini-
lateral boreholes
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15 in a single trip. The jetting hose 1595 may be as short as 10 feet or as
long as 300 feet or
even 500 feet, depending on the thickness and compressive strength of the
formation or the
desired geo-trajectory of each lateral borehole.
[00193] Figure 4 is a longitudinal, cross-sectional view of the external
system 2000 of the
downhole hydraulic jetting assembly 50 of Figure 2, in one embodiment. The
external system
2000 is presented within the string of production casing 12. For
clarification, Figure 4 presents
the external system 2000 as "empty"; that is, without containing the
components of the internal
system 1500 described above in connection with the Figure 3 series of
drawings. For example,
the jetting hose 1595 is not shown. However, it is understood that the jetting
hose 1595 is largely
contained in the external system during run-in and pull-out.
[00194] In presenting the components of the external system 2000, it is
assumed that the
system 2000 is run into production casing 12 having a standard 4.50" O.D. and
approximate 4.0"
I.D. In one embodiment, the external system 2000 has a maximum outer diameter
constraint of
2.655" and a preferred maximum outer diameter of 2.500". This O.D. constraint
provides for an
annular (i.e., between the system 2000 O.D. and the surrounding production
casing 12 ID.) area
open to flow equal to or greater than 7.0309 in2, which is the equivalent of a
9.2#, 3.5" frac
(tubing) string.
[00195] The external system 2000 is configured to allow the operator to
optionally "frac"
down the annulus between the coiled tubing conveyance medium 100 (with
attached apparatus)
and the surrounding production casing 12. Preserving a substantive annular
region between the
O.D. of the external system 2000 and the I.D. of the production casing 12
allows the operator to
pump a fracturing (or other treatment) fluid down the subject annulus
immediately after jetting
the desired number of lateral bores and without having to trip the coiled
tubing 100 with attached
apparatus 2000 out of the child wellbore 4. Thus, multiple stimulation
treatments may be
performed with only one trip of the assembly 50 in to and out of the child
wellbore 4. Of course,
the operator may choose to trip out of the wellbore for each frac job, in
which case the operator
would utilize standard (mechanical) bridge plugs, frac plugs and/or sliding
sleeves. However,
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this would impose a much greater time requirement (with commensurate expense),
as well as
much greater wear and fatigue of the coiled tubing-based conveyance medium
100.
[00196] Figure 4A-1 is a longitudinal, cross-sectional view of a "bundled"
coiled tubing
string 100. The coiled tubing 100 serves as a conveyance system for the
downhole hydraulic
jetting assembly 50 of Figure 2. The coiled tubing 100 is shown residing
within the production
casing 12 of a child wellbore 4, and extending through a heel 4b and into the
horizontal leg 4c.
[00197] Figure 4A-la is an axial, cross-sectional view of the coiled tubing
string 100 of
Figure 4A-1. It is seen that the illustrative coiled tubing 100 includes a
core 105. In one aspect,
the coiled tubing core 105 is comprised of a standard 2.000" O.D. (105.2) and
1.620" I.D.
(105.1), 3.68 lbm/ft. HSt110 coiled tubing string, having a Minimum Yield
Strength of 116,700
lbm and an Internal Minimum Yield Pressure of 19,000 psi. This standard sized
coiled tubing
provides for an inner cross-sectional area open to flow of 2.06 in2. As shown,
this "bundled"
product 100 includes three electrical wire ports 106 of up to .20" in
diameter, which can
accommodate up to AWG #5 gauge wire, and 2 data cable ports 107 of up to .10"
in diameter.
[00198] The coiled tubing string 100 also has an outermost, or "wrap,"
layer 110. In one
aspect, the outer layer 110 has an outer diameter of 2.500", and an inner
diameter bonded to and
exactly equal to that of the O.D. 105.2 of the core coiled tubing string 105
of 2.000".
[00199] Both the axial and longitudinal cross-sections presented in Figures
4A-1 and 4A-la
presume bundling the product 100 concentrically, when in actuality, an
eccentric bundling may
be preferred. An eccentric bundling provides more wrap layer protection for
the electrical wiring
106 and data cables 107. Such a depiction is included as Figure 4A-2 for an
eccentrically
bundled coiled tubing conveyance medium 101. Fortunately, eccentric bundling
would have no
practical ramifications on sizing pack-off rubbers or wellhead injector
components for
lubrication into and out of the child wellbore, since the O.D. 105.2 and
circularity of the outer
wrap layer 110 of an eccentric conveyance medium 101 remain unaffected.
[00200] Moving further down the external system 2000, Figure 4B presents a
longitudinal,
cross-sectional view of a crossover connection, which is the coiled tubing
crossover connection
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200. Figure 4B-la shows a portion of the coiled tubing crossover connection
200 in perspective
view. Specifically, the transition between lines E-E' and line F-F' of Figure
4B is shown. In
this arrangement, an outer profile transitions from circular to oval to bypass
the main control
valve 300.
[00201] The main functions of this crossover connection 200 are as follows:
(1) To connect the coiled tubing 100 to the jetting assembly 50 and,
specifically, to
the main control valve 300. In Figure 4B, this connection is depicted by the
steel
coiled tubing core 105 connected to the main control valve's outer wall 290 at
connection point 210.
(2) To transition electrical cables 106 and data cables 107 from the outside
of the
core 105 of the coiled tubing 100 to the inside of the main control valve 300.
This is
accomplished with a wiring port 220 facilitating the transition of
wires/cables
106/107 inside outer wall 290.
(3) To provide an ease-of-access point, such as the threaded and coupled
collars 235
and 250, for the splicing/connection of electrical cables 106 and data cables
107.
and
(4) To provide separate, non-intersecting and non-interfering pathways for
electrical
cables 106 and data cables 107 through a pressure- and fluid-protected
conduit, that
is, a wiring chamber 230.
[00202] The next component in the external system 2000 is the main control
valve 300.
Figure 4C provides a longitudinal, cross-sectional view of the main control
valve 300. Figure
4C-la provides an axial, cross-sectional view of the main control valve 300,
taken across line
G-G' of Figure 4C. The main control valve 300 will be discussed in connection
with both
Figures 4C-1 and 4C-la together.
[00203] The function of the main control valve 300 is to receive high
pressure fluids pumped
from within the coiled tubing 100, and to selectively direct them either to
the internal system
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1500 or to the external system 2000. The operator sends control signals to the
main control valve
300 by means of the wires 106 and/or data cable ports 107.
[00204] The main control valve 300 includes two fluid passages. These
comprise a hydraulic
fluid passage 340 and a jetting fluid passage 345. Visible in Figures 4C, 4C-
la and 4C-lb
(longitudinal cross-sectional, axial cross-sectional, and perspective view,
respectively) is a
sealing passage cover 320. The sealing passage cover 320 is fitted to form a
fluid-tight seal
against inlets of both the hydraulic fluid passage 340 and the jetting fluid
passage 345. Of
interest, Figure 4C-lb presents a three dimensional depiction of the passage
cover 320. This
view illustrates how the cover 320 can be shaped to help minimize frictional
and erosional
effects.
[00205] The main control valve 300 also includes a cover pivot 350. The
passage cover 320
rotates with rotation of the passage cover pivot 350. The cover pivot 350 is
driven by a passage
cover pivot motor 360. The sealing passage cover 320 is positioned by the
passage cover pivot
350 (as driven by the passage cover pivot motor 360) to either: (1) seal the
hydraulic fluid
passage 340, thereby directing all of the fluid flow from the coiled tubing
100 into the jetting
fluid passage 345, or (2) seal the jetting fluid passage 345, thereby
directing all of the fluid flow
from the coiled tubing 100 into the hydraulic fluid passage 340.
[00206] The main control valve 300 also includes a wiring conduit 310. The
wiring conduit
310 carries the electrical wires 106 and data cables 107. The wiring conduit
310 is optionally
elliptically shaped at the point of receipt (from the coiled tubing transition
connection 200, and
gradually transforms to a bent rectangular shape at the point of discharging
the wires 106 and
cables 107 into the jetting hose carrier system 400. Beneficially, this bent
rectangular shape
serves to cradle the jetting hose conduit 420 throughout the length of the
jetting hose carrier
system 400.
[00207] Figure 4 also shows a jetting hose carrier system 400 as part of
the external system
2000. The jetting hose carrier system 400 includes a jetting hose conduit (or
jetting hose carrier)
420. The jetting hose carrier 490 houses, protects, and stabilizes the
internal system 1500 and,
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particularly, the jetting hose 1595. The micro-annulus 1595.420 referenced
above resides
between the jetting hose 1595 and the surrounding jetting hose carrier 490.
[00208] The length of the jetting hose carrier 490 is quite long, and
should be approximately
equivalent to the desired length of j etting hose 1595, and thereby defines
the maximum reach of
the jetting nozzle 1600 orthogonal to the wellbore 4, and the corresponding
length of the mini-
laterals 15. The inner diameter specification defines the size of the micro-
annulus 1595.420
between the jetting hose 1595 and the surrounding jetting hose conduit 420.
The ID. should be
close enough to the O.D. of the jetting hose 1595 so as to preclude the
jetting hose 1595 from
ever becoming buckled or kinked, yet it must be large enough to provide
sufficient annular area
for a robust set of seals 1580L by which hydraulic fluid can be pumped into
the sealed micro-
annulus 1595.420 to assist in controlling the rate of deployment of the
jetting hose 1595, or
assisting in hose retrieval.
[00209] The jetting hose carrier system 400 also includes an outer conduit
490. The outer
conduit 490 resides along and circumscribes the jetting hose conduit 420. In
one aspect, the
outer conduit 490 and the jetting hose conduit 420 are simply concentric
strings of 2.500" O.D.
and 1.500" O.D. HSt100 coiled tubing, respectively. The jetting hose conduit
420 is sealed to
and contiguous with the jetting fluid passage 345 of the main control valve
300. When high
pressure jetting fluid is directed by the valve 300 into the jetting fluid
passage 345, the fluid
flows directly and only into the jetting hose conduit 420 and then into the
jetting hose 1595.
[00210] A separate annular area exists between the inner (jetting hose)
conduit 420 and the
surrounding outer conduit 490. The annular area is also fluid tight, directly
sealed to and
contiguous with the hydraulic fluid passage 340 of the control valve 300. When
high pressure
hydraulic fluid is directed by the main control valve 300 into the hydraulic
fluid passage 340,
the fluid flows directly into the conduit-carrier annulus.
[00211] The external system 2000 next includes the second crossover
connection 500,
transitioning to the jetting hose pack-off section 600. The main function of
the jetting hose pack-
off section 600 is to "pack-off', or seal, the annular space between the
jetting hose 1595 and the
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surrounding inner conduit 620. The jetting hose pack-off section 600 is a
stationary component
of the external system 2000. Through transition 500, and partially through
pack-off section 600,
there is a direct extension of the micro-annulus 1595.420. This extension
terminates at the
pressure/fluid seal of the jetting hose 1595 against the inner faces of seal
cups making up a pack-
off seal assembly.
[00212] Immediately prior to this terminus point is the location of a
pressure regulator valve.
The pressure regulator valve serves to either communicate or segregate the
annulus 1595.420
from the hydraulic fluid running throughout the external system 2000. The
hydraulic fluid takes
its feed from the inner diameter of the coiled tubing conveyance medium 100
(specifically, from
the I.D. 105.1 of coiled tubing core 105) and proceeds through the continuum
of hydraulic fluid
passages 240, 340, 440, 540, 640, 740, 840, 940, 1040, and 1140, then through
the transitional
connection 1200 to the coiled tubing mud motor 1300, and eventually
terminating at the tractor
1350 (or, terminating at the operation of some other conventional downhole
application, such as
a hydraulically set retrievable bridge plug.)
[00213] Additional details concerning the jetting hose conduit 420, the
outer conduit 490, the
crossover section 500, the regulator valve and the pack-off section 600 are
taught in U.S. Patent
No. 9,976,351 referenced several times above.
[00214] Returning to Figure 4, and as noted above, the external system 2000
also includes a
whipstock 1000. The jetting hose whipstock 1000 is a fully reorienting,
resettable, and
retrievable whipstock means similar to those described in the precedent works
of U.S.
Provisional Patent Application No. 61/308,060 filed February 25, 2010, U.S.
Patent No.
8,752,651 issued June 17, 2014, and U.S. Patent No. 8,991,522 issued March 31,
2015. Those
applications are again referred to and incorporated herein for their
discussions of setting,
actuating and indexing the whipstock. Accordingly, detailed discussion of the
jetting hose
whipstock 1000 will not be repeated herein.
[00215] Figure 4E provides a longitudinal cross-sectional view of a portion
of the wellbore
4 from Figure 2. Specifically, the jetting hose whipstock 1000 is seen. The
jetting hose
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whipstock 1000 is in its set position, with the upper curved face 1050.1 of
the whipstock 1050
receiving a jetting hose 1595. The jetting hose 1595 is bending across the
hemispherically-
shaped channel that defines the face 1050.1. The face 1050.1, combined with
the inner wall of
the production casing 12, forms the only possible pathway within which the
jetting hose 1595
can be advanced through and later retracted from the casing exit "W" and
lateral borehole 15.
[00216] A nozzle 1600 is also shown in Figure 4E. The nozzle 1600 is
disposed at the end
of the jetting hose 1595. Jetting fluids are being dispersed through the
nozzle 1600 to initiate
formation of a mini-lateral borehole into the formation. The jetting hose 1595
extends down
from the inner wall 1020 of the jetting hose whipstock member 1000 in order to
deliver the
nozzle 1600 to the whipstock member 1050.
[00217] As discussed in U.S. Patent No. 8,991,522, the jetting hose
whipstock 1000 is set
utilizing hydraulically controlled manipulations. In one aspect, hydraulic
pulse technology is
used for hydraulic control. Release of the slips is achieved by pulling
tension on the tool. These
manipulations were designed into the whipstock member 1000 to accommodate the
general
limitations of the conveyance medium (conventional coiled tubing) 100, which
can only convey
forces hydraulically (e.g., by manipulating surface and hence, downhole
hydraulic pressure) and
mechanically (i.e., tensile force by pulling on the coiled tubing, or
compressive force by utilizing
the coiled tubing's own set-down weight).
[00218] The whipstock 1000 is herein designed to accommodate the delivery
of wires 106
and data cables 107 further downhole. To this end, a wiring chamber 1030
(conducting electrical
wires 106 and data cables 107) is provided. Power and data are provided from
the external
system 2000 to conventional logging equipment 1400, such as a Gamma Ray ¨
Casing Collar
Locator logging tool, in conjunction with a gyroscopic tool. This would be
attached immediately
below a conventional mud motor 1300 and coiled tubing tractor 1350. Hence, for
this
embodiment, hydraulic conductance through the whipstock 1000 is desirable to
operate a
conventional ("external") hydraulic-over-electric coiled tubing tractor 1350
immediately below,
and electrical (and preferably, fiber optic) conductance to operate the
logging sonde 1400 below
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the coiled tubing tractor 1350. The wiring chamber 1030 is shown in the cross-
sectional views
of Figures 4E-la and 4E-lb, along lines 0-0' and P-P', respectively, of Figure
4E.
[00219] A hydraulic fluid chamber 1040 is also provided along the jetting
hose whipstock
1000. The wiring chamber 1030 and the fluid chamber 1040 become bifurcated
while
transitioning from semi-circular profiles (approximately matching their
respective counterparts
930 and 940 of the upper swivel 900) to a profile whereby each chamber
occupies separate end
sections of a rounded rectangle (straddling the whipstock member 1050). Once
sufficiently
downstream of the whipstock member 1050, the chambers can be recombined into
their original
circular pattern, in preparation to mirror their respective dimensions and
alignments in a lower
swivel 1100. This enables the transport of power, data, and high pressure
hydraulic fluid through
the whipstock member 1000 (via their respective wiring chamber 1030 and
hydraulic fluid
chamber 1040) down to the mud motor 1300.
[00220] Figures 2 and 4 also show an upper swivel 900 and a lower swivel
1100. The swivels
900, 1100 are mirror images of one another. Below the whipstock member 1000
and the nozzle
1600 but above the tractor 1350 is an optional lower swivel 1100. The upper
swivel 900 allows
the whipstock 1000 to rotate, or index, relative to the stationary external
system 2000. Similarly,
the lower swivel 1100 allows the whipstock 1000 to rotate relative to any
downhole tools, such
as a mud motor 1300 or a coiled tubing tractor 1350.
[00221] Logging tools 1400, a packer, or a bridge plug (preferably
retrievable, not shown)
may also be provided. Note that, depending on the length of the horizontal
portion 4c of the
wellbore 4, the respective sizes of the conveyance medium 100 and production
casing 12, and
hence the frictional forces to be encountered, more than one mud motor 1300
and/or CT tractor
1350 may be needed. The packer or retrievable bridge plug are set before any
fracturing fluids
are injected.
[00222] Typically, the packer or bridge plug is set between two distinct
frac stages. In the
sequential completion (or recompletion) of a horizontal wellbore, the packer
or bridge plug is
set above the perforations (or casing exits or casing collars) corresponding
to the frac stage that
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has just been pumped, and below the perforations (or casing exits or casing
collars) correlative
to the next frac stage to be pumped. Note that it may be advantageous to run a
bottom hole
pressure measurement device (called a pressure "bomb") below the packer or
bridge plug and
obtain real-time data from same. Alternatively, it may be further advantageous
to run dual
bombs, one below and one above the packer. This pressure data is helpful in
determining both:
(1) the integrity of the pressure seal being provided by the packer or bridge
plug; and (2) whether
or not there may be behind pipe (i.e., behind the production casing) pressure
communication
between frac stages.
[00223] In cases where previous frac stages' multi-lateral boreholes were
created through
ports in a ported casing collar, and those ports have subsequently been closed
off after receipt of
frac stimulation, then a packer or bridge plug need not be set in order to
provide zonal isolation
for the next frac through those casing exit- or port-initiated UDP' s about to
be fracked in the
next stage. Notwithstanding, the packer or bridge plug could be set as a
safeguard to insure zonal
isolation, that is, as insurance to the leaking of a closed sleeve port that
had failed. In this
instance, if a pressure bomb were to indicate communication of treating
pressures from below,
and these same pressure readings had been monitored sequentially (without
incident) while
working up the hole, then that is a positive indication of communication from
only the previous
stage.
[00224] It is anticipated that, in preparation for a subsequent hydraulic
fracturing treatment in
a horizontal child wellbore 4c, an initial borehole 15 will be jetted
substantially perpendicular to
and at or near the same horizontal plane as the child wellbore 4c, and a
second lateral borehole
will be jetted at an azimuth of 1800 rotation from the first (again,
perpendicular to and at or near
the same horizontal plane as the child wellbore). In thicker formations,
however, and particularly
given the ability to steer the jetting nozzle 1600 in a desired direction,
more complex lateral
bores may be desired. Similarly, multiple lateral boreholes (from multiple
setting points
typically close together) may be desired within a given "perforation cluster"
that is designed to
receive a single hydraulic fracturing treatment stage. The complexity of
design for each of the
lateral boreholes will typically be a reflection of the hydraulic fracturing
characteristics of the
host reservoir rock for the pay zone 3. For example, an operator may design
individually
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contoured lateral boreholes within a given "cluster" to help retain a
hydraulic fracture treatment
predominantly "in zone." This "borehole cluster" would then be analogous to
"perf clusters"
commonly used in horizontal well completions today.
[00225] It can be seen that an improved downhole hydraulic jetting assembly
50 is provided
herein. The assembly 50 includes an internal system 1500 comprised of a
guidable jetting hose
and jetting nozzle that can jet both a casing exit and a subsequent lateral
borehole in a single
step. The assembly 50 further includes an external system 2000 containing,
among other
components, a carrier apparatus that can house, transport, deploy, and retract
the internal system
to repeatably construct the requisite lateral boreholes during a single trip
into and out of a child
wellbore 4, and regardless of its inclination. The external system 2000
provides for annular frac
treatments (that is, pumping fracturing fluids or acids down the annulus
between the coiled
tubing deployment string and the production casing 12) to treat newly jetted
lateral boreholes.
When combined with stage isolation provided by a packer and/or spotting
temporary or
retrievable plugs, thus providing for repetitive sequences of plug-and-UDP-and-
frac, completion
of the entire horizontal section 4c can be accomplished in a single trip.
[00226] In one aspect, the assembly 50 is able to utilize the full I.D. of
the production casing
12 in forming the bend radius 1599 of the jetting hose 1595, thereby allowing
the operator to use
a jetting hose 1595 having a maximum diameter. This, in turn, allows the
operator to pump
jetting fluid at higher pump rates, thereby generating higher hydraulic
horsepower at the jetting
nozzle 1600 at a given pump pressure. This will provide for substantially more
power output at
the jetting nozzle, which will enable:
(1) optionally, jetting larger diameter lateral boreholes within the target
formation;
(2) optionally, achieving longer lateral lengths;
(3) optionally, achieving greater erosional penetration rates; and
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(4) achieving erosional penetration of higher strength and
threshold pressure (am
and PTh) oil/gas formations heretofore considered impenetrable by existing
hydraulic jetting technology.
[00227] Also of significance, the internal system 1500 allows the jetting
hose 1595 and
connected jetting nozzle 1600 to be propelled independently of a mechanical
downhole
conveyance medium. The jetting hose 1595 is not attached to a rigid working
string that
"pushes" the hose and connected nozzle 1600, but instead uses a hydraulic
system that allows
the hose and nozzle to travel longitudinally (in both upstream and downstream
directions) within
the external system 2000. It is this transformation that enables the subject
system 1500 to
overcome the "can't-push-a-rope" limitation inherent to all other hydraulic
jetting systems to
date. Further, because the subject system does not rely on gravitational force
for either
propulsion or alignment of the jetting hose/nozzle, system deployment and
hydraulic jetting can
occur at any angle and at any point within the host child wellbore 4 to which
the assembly 50
can be "tractored" in.
[00228] The downhole hydraulic jetting assembly allows for the formation of
multiple mini-
laterals, or bore holes, of an extended length and controlled direction, from
a single child
wellbore. Each mini-lateral may extend from 10 to 500 feet, or greater, from
the child wellbore.
As applied to horizontal wellbore completions in preparation for subsequent
hydraulic fracturing
("frac") treatments in certain geologic formations, these small lateral
wellbores may yield
significant benefits to optimization and enhancement of fracture (or fracture
network) geometry,
SRV creation, and subsequent hydrocarbon production rates and reserves
recovery. By enabling:
(1) better extension of the propped fracture length; (2) better confinement of
the fracture height
within the pay zone; (3) better placement of proppant within the pay zone; and
(4) further
extension of a fracture network prior to cross-stage breakthrough, the lateral
boreholes may yield
significant reductions of the requisite fracturing fluids, fluid additives,
proppants, fracture
breakdown and fracture propagation pressures, hydraulic horsepower, and hence
related
fracturing costs previously required to obtain a desired fracture geometry, if
it was even
attainable at all. Further, for a fixed input of fracturing fluids, additives,
proppants, and
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horsepower, preparation of the pay zone with lateral boreholes prior to
fracturing could yield
significantly greater Stimulated Reservoir Volume, to the degree that well
spacing within a given
field may be increased. Stated another way, fewer wells may be needed in a
given field to attain
a certain production rate, production decline profile, and reserves recovery,
providing a
significance of cost savings. Further, in conventional reservoirs, the
drainage enhancement
obtained from the lateral boreholes themselves may be sufficient as to
preclude the need for
subsequent hydraulic fracturing altogether.
[00229] As an additional benefit, the downhole hydraulic j etting assembly
50 and the methods
herein permit the operator to apply radial hydraulic jetting technology
without "killing" the
parent wellbore. In addition, the operator may jet radial lateral boreholes
from a horizontal child
wellbore as part of a new well completion. Still further, the jetting hose may
take advantage of
the entire I.D. of the production casing. Further yet, the reservoir engineer
or field operator may
analyze geo-mechanical properties of a subject reservoir, and then design a
fracture network
emanating from a customized configuration of directionally-drilled lateral
boreholes. Further
still, the operator may control a direction of the lateral boreholes to avoid
a frac hit with a
neighboring offset wellbore.
[00230] In yet another aspect, the method of the present invention allows
the operator to capture
stranded or "hemmed in" oil and/or gas reserves in the general direction of
the first lateral borehole
from the child wellbore. In some situations, these measures are beneficial to
not only maximize
child well performance, but also to protect correlative rights. That is, the
method of the present
invention mays serve not only for protection of a parent wellbore, but for
procurement of otherwise
stranded or "hemmed in" reserves.
[00231] The hydraulic jetting of lateral boreholes may be conducted to
enhance fracture and
acidization operations during completion. As noted, in a fracturing operation,
fluid is injected
into the formation at pressures sufficient to separate or part the rock
matrix. In contrast, in an
acidization treatment, an acid solution is pumped at bottom-hole pressures
less than the pressure
required to break down, or fracture, a given pay zone. (In an acid frac,
however, pump pressure
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intentionally exceeds formation parting pressure.) Examples where the pre-
stimulation jetting
of lateral boreholes may be beneficial include:
(a) prior to hydraulic fracturing (or prior to acid fracturing) in order to
help
confine fracture (or fracture network) propagation within a pay zone and to
develop fracture (network) lengths a significant distance from the child
wellbore before any boundary beds are ruptured, or before any cross-stage
fracturing can occur; and
(b) using lateral boreholes to place stimulation from a matrix acid
treatment far
beyond the near-wellbore area before the acid can be "spent," and before
pumping pressures approach the formation parting pressure.
[00232] The downhole hydraulic jetting assembly 50 and the methods herein
permit the
operator to conduct acid fracturing operations through a network of lateral
boreholes formed
through the use of a very long jetting hose and connected nozzle that is
advanced through the rock
matrix. In one aspect, the operator may determine a direction of a pressure
sink in the reservoir,
such as from an adjacent producer, and hence anticipate that adjacent producer
is a "hit" target.
The operator may then form one or more lateral boreholes in an orthogonal
direction, and then
conduct acid fracturing through that borehole. In this instance, assuming the
greatest principal
stress is in the vertical due to overburden, fractures will typically open in
the vertical direction,
and propagate along the top and bottom "weak points" of the lateral boreholes.
[00233] The operator may alternatively consider or determine a flux-rate of
acid (or other
formation-dissolving fluid) in the rock matrix. In this instance, the acid is
not injected at a
formation parting pressure, but allows dissolution to form in the direction(s)
of the greatest
concentrations of reactants within the rock matrix that first "spend" the
acid. Note this procedure
may be highly desirable for stimulating oil and/or gas pay zones that are "on
water". That is,
these formations have an oil/water or gas/water contacts in such close
proximity below the
desired azimuth(s) of the UDP's such that pumping the acid above formation
parting pressures
would risk "fracking into water". Note a common result of such a misstep is
that the wellbore
subsequently "cones" water. That is, because the pay zone has a higher
relative permeability to
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water (typically because it is a "water wet" reservoir; that is, due to
capillary pressure effects,
the first fluid layer contacting the rock matrix is water), the well will
produce significantly more
water than oil and/or gas... often by such a magnitude of disproportion that
continued production
of the well is unprofitable. Hence, pumping acid into the UDP's (below
formation parting
pressures) and allowing for near-UDP dissolution may be the best stimulation
alternative
available. This could even be the case for horizontal, open hole completions,
typically in highly
competent carbonate reservoirs, such as the many prolific pay zones found in
the Middle East.
Note that only slight modifications to the jetting assembly 50 would be
required to accommodate
these open hole completions.
[00234] The downhole hydraulic jetting assembly 50 and the methods herein
also permit the
operator to pre-determine a path for the jetting of lateral boreholes. Such
boreholes may be
controlled in terms of length, direction or even shape. For example, a curved
borehole or each
"cluster" of curved boreholes may be intentionally formed to further increase
SRV exposure of
the formation 3 to the wellbore 4c.
[00235] The downhole hydraulic jetting assembly 50 and the methods herein
also permit the
operator to re-enter an existing wellbore that has been completed in an
unconventional
formation, and "re-frac" the wellbore by forming one or more lateral boreholes
using hydraulic
jetting technology. The hydraulic jetting process would use the hydraulic
jetting assembly 50 of
the present invention in any of its embodiments. There will be no need for a
workover rig, a ball
dropper / ball catcher, drillable seats or sliding sleeve assemblies. For such
a recompletion in a
single trip, even in a horizontal wellbore 4c, annular frac' s (or re-frac' s)
could still be performed
(while the jetting assembly 50 remains in the wellbore) by first pumping a
pump-able diverting
agent (such as Halliburton's "BioVertg" NWB Biodegradable Diverting Agent) to
temporarily
plug off existing perforations and fractures, then jetting the desired UDP(s)
comprising a target
"borehole cluster", followed by pumping the frac stage targeting stimulation
along the jetted
UDP' s. Note given the packer within the jetting assembly 50, divertant would
need only be
applied the perf s/frac's located uphole of the target borehole cluster.
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[00236] Finally, and as discussed in much greater detail below, the
downhole hydraulic jetting
assembly 50 permits the operator to select a distance of lateral boreholes
generated from the
horizontal leg, or to select an orientation or traj ectory of the lateral
boreholes relative to the
horizontal leg, or to sidetrack off of an existing lateral borehole, or even
to change a trajectory
during lateral borehole formation. All of this is useful for avoiding a frac
hit in an offset well,
or seeking out what would otherwise be stranded reserves.
[00237] As noted above, the present disclosure includes an alternate
embodiment for an
indexing whipstock, that is, an alternative to the whipstock 1000 of Figure
4E. As an alternative,
customized ported casing collars 4000 may be strategically placed between
joints of production
casing 12 during completion of the child wellbore 4. The collars are
configured to mateably
receive the alternate whipstock. Once received, a force is exerted upon the
whipstock that opens
a portal in the casing collar, such that the alignment of the portal is in
direct alignment with the
curved face of the whipstock, thereby continuing the defined path for the
jetting hose 1600 and
precluding the need to erosionally bore an exit through the casing.
[00238] The portals are selectively opened and closed using the mating
whipstock 3000. The
whipstock 3000 utilizes alignment blocks 3400 and shift dogs 3200 to engage
and manipulate an
inner sleeve 4200 of the casing collar4000. Once the portals are opened, the
hydraulic jetting
assembly 50 can be deployed to create the Ultra Deep Perforations (UDP' s) (or
lateral boreholes)
15 in the reservoir rock 3.
[00239] The specially-designed collars 4000 have tensile and compressive
strengths and burst
and collapse resistances that are at or near those of the production casing
and, if desired, can be
cemented into place simultaneously with cementing the production casing.
Similarly, the collars
4000 can conduct stimulation fluids at pressure tolerances at or near that of
the production casing.
Preferably, the collars have ID's approximately the same as the production
casing; i.e., they are
"full opening".
[00240] Figure 4MW presents a cross-sectional view of the whipstock 3000,
which may be
used in lieu of the whipstock 1000 of Figure 4E. The whipstock 3000 defines an
elongated
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tubular body 3100 that is part of the external system 2000. The whipstock 3000
has an upper
end and a lower end. The upper end is connected to the upper swivel 900, and
can be releasably
fixed within an inner sleeve 4200 of a ported casing collar 4000 (discussed
below).
[00241] Figure 4MW depicts how the whipstock 3000, after being mateably
received by the
casing collar 4000, has manipulated the inner sleeve 4200 such that its portal
4210.S is in
alignment with the outer sleeve's portal 4110.W.
[00242] Figure 4MW.1 demonstrates the exit portal 3200 in greater detail.
Figure 4MW.1
is an exploded view of the whipstock 3000 wherein a jetting hose exit portal
3200 is aligned with
portals 4210.S and 4110.W of the casing collar. Portal 4210.S resides along
the inner sleeve
4200 while portal 4110.W resides along an outer sleeve 4100. In this view, the
inner sleeve
4200 has been rotated so that portal 4210.S is aligned with portal 4110.W,
thereby providing a
casing exit "W."
[00243] The inner diameter of the whipstock 3000 represents a bending
tunnel 3050. The
bending tunnel 3050 has a face 3001 that serves the same function as the
whipstock face 1050.1
depicted in Figure 4E. In this respect, the bending tunnel 3050 provides the
"three touch points"
for the jetting hose 1595 and jetting nozzle 1600 as it traverses across the
whipstock face 1050.1
Of interest, the first touch point is provided at a heel 3100 of the hose
bending tunnel 3050.
[00244] The hose bending tunnel 3050 is configured to receive the jetting
hose 1600 at the
upstream end. The hose bending tunnel 3050 terminates at an exit portal 3200,
which is above
the downstream end of the whipstock 3000. The hose bending tunnel 3000 closely
receives the
jetting hose 1600 as it is extruded from the jetting hose carrier, and
delivers it to the exit portal
3200.
[00245] Of interest, it can be seen in Figure 4MW.1 how the customized
contours of portals
4210.S and 4110.W continue the trajectory of the whipstock' s bending tunnel
3050 from its
terminus at the jetting hose exit portal 3200. In so doing, the bend radius
now available to the
jetting hose 1595 has increased from "R" to "R' ", as depicted.
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[00246] The whipstock 3000 provides all other features of the whipstock
assembly 1000
discussed above, including conducting hydraulic fluid through chamber 1040,
conducting
electrical and or fiber optic cable through chamber 1030, hydraulic operation
and indexing, and
other features. A presentation of these features has not been repeated in
Figures 4MW, 4MW.1,
4MW.2 and 4MW.2.SD to avoid redundancy.
[00247] During operation, the whipstock 3000 is run into the wellbore 4 as
part of the
downhole assembly 50. The ported casing collars 4000 are strategically located
between joints
of production casing 12 during the completion of the child wellbore 4. As
noted, the collars
4000 are configured to mateably receive the whipstock 3000. Once the whipstock
3000 reaches
the depth of a selected casing collar 4000, the whipstock 3000 will latch into
slots provided along
the inner diameter of the inner sleeve 4200.
[00248] Once received, a force is exerted upon the whipstock 3000 that
shifts the inner sleeve
4200 such that an inner sleeve portal is indirect alignment with a like portal
in the outer sleeve
4100. When in the opened position, both of these co-aligned portals are also
in direct alignment
with the curved face 3001 of the whipstock 3000, thereby continuing the
defined path for the
jetting hose 1595 and precluding the need to erosionally bore an exit through
the casing. Note
that as shown in Figure 4MW.1 the inner faces of these portals themselves can
be curved such
that they continue the radius of curvature defined by the whipstock face 3001.
[00249] Figure 4MW.2 is an enlarged, cross-sectional view of the whipstock
3000 of Figure
4MW.1. Here, the whipstock 3000 is rotated 90 about a longitudinal axis;
hence, the hose
bending tunnel 3050 and the exit portal 3200 are not visible. Of interest,
opposing "shift dogs"
3200 are shown. The shift dogs 3200 reside on opposing outer surfaces of the
whipstock 3000,
and extend out from the outer diameter of the whipstock 3000.
[00250] Figure 4MW.2.SD is an exploded, cross-sectional view of Figure
4MW.2. One of
the spring-loaded shift dogs 3201 is shown. The opposing shift dogs 3201 are
designed to
releasably mate with a "shift dog groove" 4202 located along the inner sleeve
4200 of the ported
casing collar 4000. The shift dog grooves 4202 are shown in Figure 4PCC.1
discussed below.
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Each shift dog 3201 includes a beveled tip 3210. In addition, each shift dog
3201 includes a
spring 3250 that is held in compression. The springs 3250 bias the respective
beveled tips 3210
outwardly.
[00251] The whipstock 3000 also includes a pair of alignment blocks 3400.
Figure
4MW.2.AB is an exploded, cross-sectional view of a portion of one of the
spring-loaded
alignment blocks 3400 of Figure 4MW.2. The springs 3450 between the alignment
blocks 3400
and the whipstock 3000 act to bias the alignment blocks 3400 outwardly. Each
of the alignment
blocks 3450 represents an area of enlarged outer diameter along the whipstock
3000.
[00252] The alignment blocks 3400 are dimensioned to be received by a
contoured profile
(referred to below as "beveled entries" 4211 along the inner sleeve 4200 of
the ported casing
collar 4000. Figure 4PCC.1 is a cross-sectional view of the ported casing
collar 4000. The
ported casing collar 4000 is dimensioned to receive the whipstock 3000 and to
be manipulated
by the whipstock 3000 using the mating alignment blocks 3400, shift dogs 3201
and shift dog
grooves 4202.
[00253] Figure 4PCC.1.SDG is an exploded, longitudinal cross-sectional view
of a shift dog
groove 4202 that resides in the ported casing collar 4000 of Figure 4PCC.1.
The shift dog
groove 4202 is formed within a body 4201 of the inner sleeve 4200. The shift
dog groove 4202
is dimensioned to receive the shift dogs 3200 of the whipstock 3000.
[00254] Returning to Figure 4PCC.1, the casing collar 4000 includes two
beveled entries
4211. The beveled entries 4211 are configured to receive or act upon the pair
of alignment
blocks 3400 of Figures 4MW.2 and 4MW.2.AB. Specifically, the beveled entries
4211 form
shoulders that contact the alignment blocks 3400. The contour of these mirror-
image beveled
entries 4211 force the whipstock 3000 to rotate until the alignment blocks
3400 engage opposing
inner sleeve alignment slots 4212. A continued downstream push on the e-coil
conveyance
medium 100 moves the alignment blocks 3400 further into the alignment slots
4212 in the inner
sleeve 4200 until the spring-loaded shift dogs 3201 on the whipstock 3000
engage the shift dog
grooves 4202 in the inner sleeve body 4201. Once the shift dogs 3201 are
engaged into the
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respective shift dog grooves 4202, the whipstock 3000 can rotate the inner
sleeve 4200 via the
alignment blocks 3400 and shift the inner sleeve 4200 axially through the
shift dogs 3201.
[00255] Once the whipstock 3000 is aligned within and locked into the inner
sleeve 4200, the
combined torsional and axial movements of the whipstock 3000 allows the
whipstock 3000 to
rotate and/or translate the inner sleeve 4200 to shift the inner sleeve 4200
into any of five
positions. The five positions are depicted in a control slot pattern 4800 in
Figure 4PCC.1.CSP.
[00256] Figure 4PCC.1.CSP is a schematic view showing a progression of the
torsional and
axial movements of the whipstock 3000. More specifically, Figure 4PCC.1.CSP is
a two-
dimensional "roll-out" view of a control slot pattern for the inner sleeve
4200 of the ported casing
collar 4000, showing each of five possible slot positions.
[00257] In Figure 4PCC.1.CSP, a control slot 4800 is shown. The control
slot 4800 is milled
into the outer diameter of the inner sleeve 4200. In each of the five
position, the inner sleeve
4200 is held in place and guided through the control slot 4800 by two opposing
torque pins 4500.
The torque pins 4500 are seen in each of Figures 4PCC.1 and 4PCC.1.CSP. The
torque pins
4500 protrude through the outer sleeve 4100 into the two mirror-image control
slots 4800.
[00258] The control slots 4800 are designed to selectively align portals in
the inner 4200 and
outer 4100 sleeves. The inner sleeve 4200 has, for example, portals 4210.S,
4210.W, 4210Dd
and 4210Du. The outer sleeve 4100 has, for example, portals 4110.W and 4110.E
(indicating
east and west). These portals are all illustrated in Figure 4PCC.2.
[00259] In position "1," all portals of the inner sleeve 4200 and the outer
sleeve 4100 are out
of alignment, meaning that the ported casing collar 4000 is closed. Of
interest, the casing collar
4000 is run into the wellbore 4 as an integral part of the casing string 12 in
the closed position
[00260] In position "2," portals 4210.S and 4110.E are in alignment,
providing an "East
Open" position.
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[00261] In position "3," portals 4210.S and 4110.W are in alignment,
providing a "West
Open" position.
[00262] In position "4," portals 4110.W and 4210.Du are aligned as are
portals 4110.E and
4210.Dd, meaning that the ported casing collar 4000 is fully open.
[00263] In position "5," portals of the inner sleeve 4200 and the outer
sleeve 4100 are again
out of alignment, meaning that the ported casing collar 4000 is once again
closed.
[00264] It is noted that in all of these torque pin positions, the outer
sleeve 4100 remains
stationary in a pre-oriented position. Stated another way, the outer sleeve
4100 is in a fixed
position throughout the manipulation and repositioning of the inner sleeve
4200. Placement of
the outer sleeve 4100 in its fixed position is aided by an optional "weighted
belly" 4900. The
weighted belly 4900 forms an eccentric profile for the outer sleeve 4100 and
urges the outer
sleeve 4100 to rotate within the horizontal leg 4C to the bottom of the bore.
[00265] Figure 4PCC.2 presents an operational series showing the relative
positions of each
of the outer sleeve's two stationary portals versus each of the inner sleeve's
three portals as the
inner sleeve 4200 is translated and rotated into each of its five possible
positions.
[00266] In position "1," injection fluids flow through the ported casing
collar 4000, but no
fluids flow through portals of the inner sleeve 4200 and the outer sleeve
4100.
[00267] In position "2," portals 4210.S and 4110.E are in alignment,
providing an "East
Open" position.
[00268] In position "3," portals 4210.S and 4110.W are in alignment,
providing a "West
Open" position.
[00269] In position "4," portals 4110.W and 4210.Du are aligned as are
portals 4110.E and
4210.Dd, meaning that the ported casing collar 4000 is fully open. Both
easterly and westerly
portals are open.
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[00270] In position "5," portals of the inner sleeve 4200 and the outer
sleeve 4100 are again
out of alignment. Injection fluids flow through the ported casing collar 4000
but do not flow
through any sleeve portals.
[00271] Figure 4PCC.3d is a series of perspective views of the ported
casing collar 4000 of
Figure 4PCC.1. Figure 4PCC.3d illustrates positions of the ported casing
collar 4000 when
placed along the production casing string 12. Each of the perspective views I
the Figure
4PCC.3d series illustrates one of the five possible positions for the inner
sleeve portals relative
to the outer sleeve portals.
[00272] First, Figure 4PCC.3d.1 shows the ported casing collar 4000 in a
position where the
inner sleeve portals and the outer sleeve portals are out of alignment. This
is the closed position
of position "1."
[00273] Figure 4PCC.3d.2 shows an alignment of portals 4210.S with portals
4110.E. Here,
the "east" ports are open. This illustrates position "2."
[00274] Figure 4PCC.3d.3 shows an alignment of portals 4210.S with portals
4110.W. Here
"west" ports are open. This is illustrative of position "3."
[00275] Figure 4PCC.3d.4 shows an alignment of all inner sleeve portals
with all outer
sleeve portals. Both the east and the west portals are open. This represents
position "4."
[00276] Figure 4PCC.3d.5 again shows the inner sleeve portals and the outer
sleeve portals
out of alignment. This is the closed position of position "5."
[00277] In each drawing of the Figure 4PCC.3d series, a hydraulic locking
swivel 5000 is
shown. The casing collar 4000 is run into the wellbore 4 in combination with
pairs of the
hydraulic locking swivels 5000 and at least one, but preferably two, standard
casing centralizers
6000. Since the outer sleeves 4100 must be able to rotate freely when the
casing collar 4000 is
placed next to a casing centralizer 6000, then the maximum O.D. of the casing
collar 4000 must
be measurably less than O.D. of a casing centralizer 6000 when in a loaded
position in gauge
hole; i.e., the bit diameter.
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[00278] The hydraulic locking swivels 5000 allow the "weighted belly" to
gravitationally
rotate the outer sleeve 4100 into the proper orientation prior to cementing.
Once the casing has
been cemented or is in the desired location in the wellbore 4, internal
pressure is applied to lock
the hydraulic locking swivels 5000 in place. Once the swivels 5000 are locked,
the ported casing
collar 4000 can be manipulated as needed to access desired portals.
[00279] Figure 4HLS is a longitudinal, cross-sectional view of the
hydraulic locking swivel
5000 as shown in the Figure 4PCC.3d series of drawings. The swivel 5000 first
comprises a
top sub 5100. The top sub 5100 represents a cylindrical body. An upper end of
the top sub 5100
comprises threads configured to connect to a string of production casing (not
shown).
[00280] The swivel 5000 also comprises a bottom sub 5500. The bottom sub
5500 also
represents a cylindrical body. Together, the top sub 5100 and the bottom sub
5500 form an inner
bore that is in fluid communication with the inner bore of the production
casing 12 and the casing
collars 4000. The inner bore of these components forms a primary flow path for
production
fluids.
[00281] A lower end of the bottom sub 5500 includes threads. These threads
also connect in
series to the production casing 12. An upper bearing 5210 is placed between an
upper end of
the bottom sub 5500 and a lower end of the top sub 5100. The upper bearing
5210 allows relative
rotational movement between the top sub 5100 and the bottom sub 5500.
[00282] A body of the top sub 5100 threadedly connects to a bearing housing
5200. The
bearing housing 5200 forms a portion of an outer diameter of the swivel 5000.
Along with the
top sub 5100, the bearing housing 5200 is stationary. The bearing housing 5200
includes a
shoulder 5201 that resides below a corresponding shoulder 5501 of the bottom
sub 5500. A
lower bearing 5220 resides between these two shoulders. Along with the upper
bearing 5210,
the lower bearing 5220 facilitates rotational movement of the bottom sub 5500
within the
wellb ore 4c.
[00283] The swivel 5000 also includes a clutch 5300. The clutch 5300 also
defines a tubular
body, and resides circumferentially around the bottom sub 5500. Shear screws
5350 fix the
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clutch 5300 to the bottom sub 5500, preventing relative rotation of the bottom
sub 5500 until the
shear screws 5350 are sheared by an axial force.
[00284] Keys 5700 reside in annular slots between the bottom sub 5500 and
the surrounding
clutch 5300. The keys 5700 provide proper alignment of the bottom sub 5500 and
the clutch
5300. In addition, o-rings 5400 reside within the annular region on opposing
ends of the keys
5700. Further, snap rings 5600 are placed along an outer diameter of the
bottom sub 5500. The
snap rings 5600 are configured to slide into a mating groove to lock the
clutch 5300 in place.
This takes place when the clutch 5300 is engaged.
[00285] Finally, a clutch cover 5310 is placed on the swivel 5000. The
clutch cover 5310 is
threadedly connected to a bottom end of the bearing housing 5200. The clutch
cover 5310 is
also stationary, meaning that it will not rotate. A bottom end of the clutch
cover 5310 extends
down and covers an upper portion of the clutch 5300. Once the shear screws
5350 are sheared,
the clutch 5300 is able to slide along the bottom sub 5500 under the clutch
cover 5310.
[00286] The hydraulic locking swivel 5000 is designed to be run in on
opposing ends of the
ported casing collar 4000. Placement of the two hydraulic locking swivels 5000
enables the
eccentrically-weighted" belly" 4900 of the outer sleeve 4100 to
gravitationally rotate into a
position 180 from true vertical, thereby pre-aligning the porta' s in the
casing collar 4000 at true
horizontal.
[00287] In operation, the casing 12 is run into the wellbore 4 and
cemented. Internal pressure
is applied to all of the swivels 5000 along the casing string 12
simultaneously. This may be done
when "bumping-the-plug" at the conclusion of cementing the casing string 12 in
place. This
internal hydraulic pressure, when first applied to the swivels 5000, will
shear their respective
shear screws 5350, thereby engaging the clutches 5300 to prevent further
rotation. Once the
clutch 5300 is engaged, the snap ring 5600 moves into a mating groove and
locks the clutch 5300
in place. No further rotation is possible through the swivels 5000 or the
attached outer sleeve
4100, nor is this locking process reversible.
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[00288] The whipstock 3000 can be run and engaged with the casing collar
4000 as described
above, and the casing collar portals can be open/closed as needed pursuant to
the operations
detailed shown in Figure 4PCC.2 and the Figure 4PCC.3d series.
[00289] Once the swivels 5000 are hydraulically released to swivel, and
once the desired
position of the inner sleeve 4200 within the casing collar 4000 is reached,
the shift dogs 3200
and the alignment blocks 3400 can be released with upstream movement of the
whipstock 3000.
Upstream movement releases the shift dogs 3200 from the shift dog grooves 4202
and allows
the alignment blocks 3400 to be removed from the alignment slots 4210.
[00290] The main functions of the ported casing collar 4000 are:
= To pre-orient the whipstock 3000, and hence the jetting hose 1595 and
attached
nozzle 1600, for a desired lateral borehole trajectory;
= To preclude the need to hydraulically bore or mechanically mill casing
exits in
the casing to form lateral boreholes; and
= To provide a way to either temporarily or permanently open up or seal off
a
specific portal within the casing collar 4000, and hence (assuming a competent
cement job) its associated UDP, at any point during the completion /
production
/ recompletion of a well.
[00291] The ported casing collar 4000 also allows an operator to:
= Provide an in situ method for favorably weakening the stress profile of a
pay zone
in a specific direction, either by:
= Jetting a lateral borehole immediately prior to a formation fracturing
operation through the open portals in the casing collar 4000; or
= Jetting a lateral borehole, then prior to fracturing, producing reservoir
fluids and commensurately drawing down reservoir pressure in the vicinity
of the pay zone immediately surrounding the lateral borehole, thus even
further weakening this respective portion of the unstimulated pay zone.
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[00292] The use of the ported casing collar 4000 and its five positions
provides for generating
lateral boreholes in an eastwardly direction, a westwardly direction, or both,
and may also serve
to isolate, and/or stimulate, and/or produce (either prior to or after
hydraulic fracturing) the
eastwardly and westwardly lateral boreholes, either individually or in tandem,
as desired.
[00293] During operation, the inner sleeve 4200 mateably receives the
hydraulic jetting
assembly 50. This may be accomplished by pins and/or dogs protruding from the
circumference
of the jetting hose assembly 50, preferably at or near the whipstock 3000.
This protruding
mechanism may employ springs to provide an outwards biasing force.
[00294] Figure 4PCC.1.CLD is an exploded, cross-sectional view of a collet
latch dog
profile 4310 of the casing collar of Figure 4PCC.1. The collet latch 4310
interacts with a collet
latch profile 4150. The collet latch profiles 4150, in turn, reside along the
outer sleeve 4100.
[00295] The protruding mechanism may also have a unique shape/profile such
as to be
mateably received by the inner sleeve 4200 of the ported casing collar 4000,
such as by
slots/grooves within the inner sleeve 4200. The slots/grooves may approximate
the mirror image
of the profile of the protruding pin/dog at or near the whipstock 3000 within
the jetting hose
assembly 50. Hence, as the hydraulic jetting assembly 50 is advanced uphole
while its protruding
pins/dogs travel within the slots/grooves of the inner sleeve 4200, they will
eventually "snug
up", or latch within the inner sleeve 4200 so as to form a temporary
mechanical connection
between the hydraulic jetting assembly 50 and the inner sleeve 4200.
[00296] It is noted that during initial latching of the whipstock 3000 to
the inner sleeve 4200,
the inner sleeve 4200 is pinned to the stationary outer sleeve 4100. Referring
again to Figure
4PCC.1, a shear screw 4700 is shown. Shear screws 4700 are employed to pin the
inner sleeve
4200 to the outer sleeve 4100.
[00297] As the protruding pins/dogs are traversed distally within the
slots/grooves of the inner
sleeve 4200, the whipstock 3000 will receive an induced rotational force.
Since at this stage the
whipstock 3000 is free to rotate, and the inner sleeve 4200 is not, this
induced torque will cause
the whipstock 4200 to rotate about bearings within the swivel assemblies 900,
1100 included in
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the tool string. As the whipstock 3000 rotates, the distal end of the
whipstock's curved face 3001
approaches alignment with a port along the inner sleeve 4200. At the point at
which the
protruding pins/dogs are "snugged up" within the slots/grooves of the inner
sleeve 4200, the
distal end of the whipstock 4200 will become precisely aligned with an inner
sleeve portal (such
as portal 4210.S shown in Figure 4MW). This portal will be placed and
contoured within the
inner sleeve 4200 such that it effectively serves as an extension of the arc
of the whipstock's
curved face 3001.
[00298] Referring back to Figure 4MW, it can be seen that the jetting hose
exit portal 3200,
the portal 4210.S of the inner sleeve 4200 and the portal 4110.W of the outer
sleeve 4100 are in
alignment. Dimensionally, the inner diameter of the inner sleeve 4100 is
approximately equal
to that of the production casing 12 itself Beneficially, any tools that could
be run in the
production casing 12 may also be run through the casing collars 4000. As
designed, this provides
an even larger bend radius R' available to the jetting hose 1595 than if the
desired degree of
jetting hose bending (for instance, 90 degrees) had to be accomplished
entirely within the I.D.
of the bending tunnel 3050.
[00299] The benefit of the small R to R' radius increase is deceptive. In
absolute magnitude,
the R to R' increase will only approximate the combined wall thicknesses of
the inner sleeve
4200 and the outer sleeve 4100; i.e., about .25" to .50". Notwithstanding,
this relatively small
incremental gain in available bend radius for selection of an appropriate
jetting hose yields an
increase in the I.D. of the jetting hose 1595 that can be utilized.
Specifically in the case of
smaller casing sizes, such as OCTG' s standard 4.5" O.D. and 4.0" ID.,
increasing the available
bend radius from 4.0" to 4.5" could mean an additional 1/8th inch in jetting
hose I.D. Over a
jetting hose length of 300 feet, this can provide a subsequent increase in
deliverable HHP to the
jetting nozzle 1600 while staying within the bend radius and burst pressure
constraints of the
larger hose 1595.
[00300] Note the maximum limit of this protrusion's extension from the O.D.
out into the
borehole should approximate the same protrusion distance (from the O.D. of the
outer sleeve
4200 out into the borehole) of the weighted belly 4900. And, (2) by including
a slot cut out of
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the inner sleeve 4200 that receives the bent jetting hose 1595 at a position
180 opposite, and
slightly above, the inner sleeve portal 4210.S. This enables the furthest
extension of the "bend"
in the jetting hose 1595 to be limited by the I.D. of the outer sleeve 4100,
instead of being
constrained by the I.D. of the inner sleeve 4200.
[00301] To accommodate the rotation of the weighted belly 4900, the ported
casing collar
4000 may also have a series of circumferential bearings. These bearings may be
located at both
the proximal and distal ends of the casing collar 4000 such that adding the
eccentric weighted
belly 4900 to the outer sleeve 4100 of the casing collar 4000 enables
gravitational force to self-
orient the exit ports at the desired exit orientation. However, it is
preferred to use the
hydraulically locked swivels 5000 described above.
[00302] Running a casing centralizer (such as centralizer 6000 shown in the
Figure 4PCC.3d
series discussed below) near one or both ends of the ported casing collar 4000
helps ensure that
the casing collar 4000 can rotate freely until it rotationally comes to rest
at the desired
orientation. As discussed above, the hydraulic jetting assembly 50 mates with
the inner sleeve
4200, and can rotate or translate the inner sleeve 4200 into its desired
position according to the
control slot 4800. Receipt of the whipstock 50 by the inner sleeve 4200 is
such that a distal end
of the whipstock face 3001 is in alignment with a pre-shaped portal 4210.S in
the inner sleeve
4200.
[00303] In another aspect, once the ported casing collar 4000 has mateably
received the
hydraulic jetting assembly 50, and once the portals of the inner sleeve 4200
are rotated by the
hydraulic jetting assembly such that the portals are in alignment with portals
of the outer sleeve
4100, the hydraulic jetting assembly 50 may further rotate both the inner 4200
and outer 4100
sleeves into the desired alignment relative to the pay zone. The requisite
rotational force may
be provided by either: (1) the same protruding mechanism that rotates the
whipstock 3000 into
its desired alignment as discussed above; or, (2) a separate rotating
mechanism, preferably of
significant torque capacity such that any bonding forces of cement, drilling
mud and filtrate to
the outer sleeve 4100 can be sheered, and similarly any binding forces due to
hole ovality and
wellbore friction can be overcome. To aid in this rotation, the outer sleeve
4100 may be coated
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with a thin film of polytetrafluoroethylene ("PTFE"; a.k.a. Chemours'
[formerly DuPont
Company's] trade name Teflon ), or some similar substance, in order to
minimize the torque
required to shear any bond that may have formed between the outer sleeve 4100
and any
subsequently circulated cement, or drilling mud, or any wellbore fluids. Note
that this ability to
rotate both sleeves 4100, 4200 simultaneously precludes the need for a
weighted belly 4900.
[00304] In yet another aspect, a rotational force exerted by the whipstock
3000 shears the set
screws 4900 that had immobilized the inner sleeve 4200 relative to the outer
sleeve 4100. A
pulling force (in the uphole direction) applied by the coiled tubing string
100 translates the inner
sleeve 4200 from its position "1' (where all portals are out of alignment and
the casing collar
4000 is sealed) into its position "2" (where selective portals of the inner
4200 and the outer 4100
sleeves are in alignment).
[00305] In one embodiment of the whipstock 3000, particularly given the
preferred
conveyance medium of e-coil versus standard coiled tubing, coupled with
delivery of electric
cable to (and actually, through) the whipstock 3000, the hydraulically powered
rotation/indexing
system is replaced with an electro-mechanical system. That is, where rotation
of the whipstock
3000 is powered by a small, high torque electric motor, and its orientation is
given in real time
by a sensor reading tool face orientation.
[00306] In another aspect, a coiled tubing tractor may be used to assist in
conveyance of the
coiled tubing sting 100 and the hydraulic jetting assembly 50 along the
horizontal leg 4c of the
wellbore 4. In any instance, the force in the uphole direction will drive the
inner sleeve 4200
into its position "2." In position "2," alignment of the jetting hose exit
portal 3200 and the inner
4210.S and the outer 4110.E portals will position the jetting nozzle and hose
to exit horizontally
in an eastwardly direction.
[00307] Figure 4PCC.3d.2 demonstrates the alignment of portals in an
eastwardly direction,
representing position "2." In this second position, an eastwardly lateral
borehole may be jetted,
and subsequently produced, and/or subsequently stimulated. Applying subsequent
translating
and/or rotating forces will align inner and outer sleeve portals to position
"3," such that the
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sleeves' portals are aligned and open, providing for jetting, producing, or
stimulating a lateral
borehole in a westwardly direction. Yet a third translation/rotation of the
inner sleeve 4200 will
align the inner and outer sleeve portals into position "4," aligning portals
in both eastwardly and
westwardly directions and thus providing for simultaneous stimulation and/or
production of both
lateral boreholes. And finally, a fourth translating force application will
shift the inner sleeve
4200 to position "5") and final position, such that all of the portals of the
outer sleeve are sealed
off.
[00308] 0-rings 4600 seal the annular interface between the inner sleeve
4200 and the
surrounding outer sleeve 4100.
[00309] Once the hydraulic jetting operation is completed and the jetting
hose 1595 and
jetting nozzle 1600 have been retrieved back into the external system 2000, a
mechanical force
can be transmitted to the casing collars 4000 along the production casing 12
via the whipstock
3000. The portals of the casing collars 4000 are then closed, that is, placed
in position "5."
When closed, the casing collars 4000 can conduct stimulation fluids at similar
I.D. dimensions
and burst/collapse tolerances as the production casing 12.
[00310] The downhole hydraulic jetting assembly 50 allows an operator to
create a network
of lateral boreholes, wherein formation of the lateral boreholes may be
controlled so as to avoid
frac hits in neighboring wells. The lateral boreholes are hydraulically
excavated into a pay zone
that exists within a surrounding rock matrix. The pay zone has been identified
as holding, or at
least potentially holding, hydrocarbon fluids.
[00311] Figure 5A is a perspective view of a hydrocarbon-producing field
500. In this view,
a child wellbore 510 is being completed adjacent to a parent wellbore 550. In
the illustrative
arrangement of Figure 5, the child wellbore 510 is a new wellbore that is
being completed
horizontally. In contrast, the parent wellbore 550 is an older wellbore also
completed
horizontally.
[00312] The child wellbore 510 has a vertical leg 512 and a horizontal leg
514. The horizontal
leg 514 extends from a heel 511 to a toe 515. The horizontal leg 514 extends
along a pay zone
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530. The horizontal leg 514 may be of any length, but is typically at least
2,000 feet. Of interest,
the horizontal leg 514 passes by or is generally parallel to the parent
wellbore 550, coming
perhaps as close as 200 feet.
[00313] In the completion of Figure 5A, frac stages 1, 2, and 3 followed
conventional
perforations placed in "clusters." These clusters were then fracked using the
common "plug-n'-
perf' technique; that is, by placing a drillable bridge plug between each
hydraulic fracturing
stage. These bridge plugs must be drilled out later, before the SRV's gained
from frac stages 1
thru 3 before frac and reservoir fluids can flow into the wellbore 511.
[00314] This typical completion technique of child well 510 is carried out
until frac stage "n",
during which time a frac hit 599 is observed in the parent wellbore 550. In
many instances, the
severity of the frac hit 599 is first indicated by a blown-out stuffing box of
the parent well 550.
[00315] An SRV 597 is shown in Figure 5A, emanating from the child wellbore
510 as a
result of frac stage "n." In the hypothetical but very real scenario depicted
in Figure 5A, the
SRV 597 grows only in one direction, and that as a very narrow "line-out"
toward a depletion
zone 598 surrounding the lateral section of parent wellbore 550. Note here the
operator's greatest
economic loss may not be: (1) the cleanout expense of parent wellbore 550, or
(2) the potential
loss of unrecoverable production and remaining reserves from the depletion
zone 598; nor even,
(3) frac costs to build so much of SRV 597 within the parent's depletion zone
598. Instead, it is
highly probable the operator's greatest economic loss is incurred by his
inability to access
hydrocarbon production and reserves from the higher reservoir pressure, and
hence production-
and reserves-rich pay zone volume depicted as 596; that is, half of the SRV
that frac stage "n"
was otherwise designed to construct.
[00316] The narrow "line-out" of the SRV from frac stage "n" toward the
depletion zone 598
is a result of the weakening of the principal horizontal stress profile within
the pay zone 530.
Such weakening is typically directly proportional to the reduction in pore
pressure. For previous
flow of hydrocarbons to be captured by a parent wellbore, the pore pressure of
the reservoir
would have been represented by a gradient from a maximum at an outer drainage
boundary,
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gradually decreasing to a minimum in the vicinity of the parent wellbore.
Commensurately, the
principal horizontal stress profile within the reservoir would follow the same
gradient:
maximum at an outer drainage boundary, minimum in the vicinity of the parent
wellbore 550.
Thus, the likelihood of frac hits increases proportionally to the pore
pressure gradient between
the locations of the existing parent 550 and the new child wellbore 510.
[00317] When a frac hit such as frac hit 599 occurs, the operator of the
parent wellbore 550
will naturally become concerned that subsequent frac stages, beginning with
the very next stage
"n+1", are going to hit parent wellbore 550 just as stage "n" did. Thus, it is
desirable in
connection with a horizontal well completion to obtain greater control over
the geometric growth
of the primary fracture network extending perpendicularly outward from the
horizontal leg 4c.
It is further desirable to actually control, or at least favorably influence,
the growth of a fracture
network and its resultant SRV while completing a newer "child" to avoid frac
hits damaging
offsetting "parent" wells and "thiefing" the subject frac stage. It is
proposed herein that this can
be accomplished through the use of one or more hydraulically-jetted mini-
lateral boreholes,
otherwise called Ultra Deep Perforations ("UDP' s"), extending from the
horizontal leg 514 in
the child wellbore 510, in a direction away from the parent wellbore.
[00318] Figure 5B is another perspective view of the hydrocarbon-producing
field 500 of
Figure 5A. Here, a mini-lateral borehole 522 has been jetted from the child
wellbore 510. The
lateral borehole 522 extends from a first casing exit location 521 along the
child wellbore 510,
and is formed transverse to the horizontal leg 514. Of course, the lateral
borehole 522 may
extend away from the horizontal leg 514 at any angle. What is significant in
Figure 5B is that
the lateral borehole 522 is formed in a direction that is moving away from the
existing parent
wellbore 550.
[00319] The lateral borehole 522 has been formed subsequent to and in the
opposite direction
of the frac hit 599 occurring from pumping stage "n." The lateral borehole 522
has also been
formed prior to pumping stage "n+1." In order to form the lateral borehole
522, the operator of
the formation fracturing operation taking place in the child wellbore 510 may
rig down the
wireline service providing the "plug-n'perf" functions, and moved in an e-coil
unit to run in a
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downhole hydraulic jetting assembly 50. Thus, the lateral borehole 522 is
formed using the
downhole hydraulic jetting assembly 50 described above, including the use of
either whipstock
1000 or whipstock 3000.
[00320] It is observed that there is nothing improper about the formation
of the lateral
borehole 522, provided that regulatory reporting requirements are met. It is
also observed from
Figure 5A that SRV's were also formed from frac stages #1, #2 and #3. This is
proper as well.
However, these SRV's 515 did not extend in only one direction (the direction
of depletion zone
598, but formed bilaterally as they were designed to do. No additional frac
hits were created.
[00321] Where the whipstock 3000 and ported casing collar 4000 are used to
form lateral
borehole 522, it is anticipated that the path established by the portals'
alignments will be
perpendicular to the longitudinal axis of production casing 12 at 90 and 270
from true vertical.
Because of the self-aligning feature of the casing collar 4000, the 90 / 270
are not essential to
the design, and could be modified as desired. For example, the portals may be
used to align the
longitudinal axis of the portals (said axis being at-or-near perpendicular to
the longitudinal axis
of the wellbore, and hence of the casing collar body itself) at 100 and 280
as to initiate lateral
boreholes parallel to a host pay zone's bedding plane having a 10 dip.
[00322] In any instance, during the formation of the lateral borehole 522
it is desirable for the
operator to obtain real-time geophysical feedback. An example of such feedback
is from micro-
seismic data. For example, if the micro-seismic data's processing and
presentation times are
truly close to "real-time", pumping operations could be shut down prior to a
"hit" 599 being
incurred. At the very least, real-time micro-seismic feedback should yield
valuable information
as to what the lateral borehole 522 configuration for the subsequent frac
stage 521 should be.
[00323] For the remainder of the child wellbore 510 completion, for each
remaining frac stage
the operator may jet lateral boreholes only in a westerly direction, and none
easterly, particularly
if he discovers lateral borehole 522 was successful in both: (1) directing SRV
596 growth westerly
for frac stage 521 ("n+1"), and (2) avoiding another frac hit 599 in parent
wellbore 550.
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[00324] In
addition, sensor tools may be used to provide real-time data describing the
downhole location and the alignment of the whipstock face 1050.1 or 3001. This
data is useful
in determining:
(1) how many degrees of re-alignment, via the whipstock face 1050.1
alignment, are
desired to direct the initial lateral borehole along its preferred azimuth;
and
(2) subsequent to jetting the first lateral borehole, how many degrees of
re-alignment
are required to direct subsequent lateral borehole(s) along their respective
preferred azimuth(s).
[00325] In
addition, the tool face sensor data received in real time, subsequent to the
whipstock 3000 being latched into a casing collar 4000, would confirm:
(3) the initial alignment of the casing collar 4000 by validation of the
weighted belly
4900 successfully orienting at 180 from true vertical;
(4) the alignments of the outer sleeve's easterly-oriented port 4110.E and
westerly-
oriented port 4110.W being oriented at 90 and 270 , respectively, from true
vertical (presuming that their longitudinal azimuths were designed for true
horizontal); and,
(5) the hydraulic locking swivels 5000 (or, at least one of them) located
at each end
of the casing collar 4000 had successfully actuated, locking the rotational
position
of the casing collar 4000 and the swivels 5000 in place. That is, throughout
the
rotational movements of the whipstock face 3001, induced by torque from an
electric motor, it can be observed whether or not the casing collar 4000 is
rotating
with it.
[00326]
The operating procedures for the whipstock 3000 and the ported casing collar
4000
are as follows.
(1)
After the hydraulic locking swivels are pressurized and hydraulically locked,
the whipstock 3000 is run inside an inner sleeve 4200 to operate the casing
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collar 4000 and to place it in the desired port-open condition such that
hydraulic
jetting and/or stimulation and/or production operations can begin.
(2) Once the whipstock 3000 is inside the inner sleeve 4200, the alignment
blocks
3400 are guided by the beveled entries 4211 to matingly rest in the axial
alignment slots 4212.
(3) Continued downstream movement of the whipstock 3000 snaps the shift
dogs
3200 into the mating shift dog groove 4202 in the inner sleeve body 4201. At
this point of engagement by the whipstock 3000, the casing collar 4000 is in
position "1," which is the run-in-hole position. all portals are sealed and
pressure-tight in the casing collar 4000.
(4) Rotating the whipstock 3000 clockwise (right-hand) applies torque to
the inner
sleeve 4200 through the alignment blocks 3400, shearing the shear screws 4700
in the lower portion of the inner sleeve 4200 and places the inner sleeve 4200
in an axial portion of the control slots 4800 relative to the torque pins
4500.
The torque pins 4500 are used to guide the inner sleeve's movement along the
path established by the control slots 4800.
(5) Moving the whipstock 3000 upstream via the shift dogs' 3200's
engagement of
shift dog groove 4202, followed by counter clockwise (left-hand) rotation
places the inner sleeve 4200 in position "2." This is the "East Hole Open"
position relative to the torque pins 4500. Further longitudinal movement is
prevented. Hydraulic jetting, stimulation and/or production operations in the
easterly direction can begin while in this position "2."
(6) To move the inner sleeve 4200 from position "2" to position "3," which
is the
"West Port Open" position, 180 of clockwise rotation is applied through
rotation of the whipstock 3000, placing the torque pins 4500 in a longitudinal
portion of the control slot 4800. This is shown in Figure 4PCC.1.CSP.
Upstream movement via the shift dogs 3200 and clockwise (right-hand) rotation
of the whipstock 3000 and matingly attached inner sleeve 4200 place the torque
pins 4500 in position "3." In this position, hydraulic jetting, stimulation
and/or
production operations in the westerly direction can begin.
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(7) Moving from position "3" to position "4" is accomplished by applying
counterclockwise (left-hand) rotation, then upstream axial movement, to the
whipstock 3000. This aligns all portals as shown in Figures 4PCC.2 and
4PCC.3d.4, meaning that both East and West Ports are open. Clockwise (right-
hand) rotation locks the inner sleeve 4200 in Position "4." Further
longitudinal
movement is again prevented and stimulation and/or production operations in
simultaneous easterly and westerly directions can begin. (Note that hydraulic
jetting is not possible in Position "4" as the whipstock's jetting hose exit
portal
3200 is no longer in alignment with a portal in the inner sleeve 4200.)
(8) Applying 90 of counterclockwise (left-hand) rotation to the whipstock
3000
followed by upstream longitudinal movement and additional counterclockwise
(left-hand) rotation places the torque pins 4500 in control slot Position "5."
This is the "Both Holes Closed" position, shown in Figures 4PCC.2 and
4PCC.3d.5. In this position, further axial movement is prevented. Straight
upstream movement (i.e. no rotation) can be applied when in any of the five
"locked" control slot positions and removes the shift dogs 3200 from the
mating
circumferential shift dog groove 4202.
Further upstream longitudinal
movement removes the alignment blocks 3400 from the alignment slots 4212,
thereby allowing the whipstock 3000 to be moved to a next casing collar 4000
along the casing string 12.
[00327]
Beneficially, the above completion protocol could include all of the lateral
boreholes
being jetted in advance of any frac equipment arriving at the child well
location. In fact, the
only necessary equipment would be the hydraulic jetting assembly 50 with the
casing collars
4000 placed along the production casing 12 to jet the lateral boreholes.
[00328]
Using the whipstock 3000, the casing collars 4000 may be selectively opened or
closed at a later time to provide for fracing through them in any sequence
desired. Additionally,
lateral boreholes jetted through the aligned portals of the casing collars
4000 may be augmented
by additional lateral boreholes jetted through the casing 12 and into the pay
zone using either the
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whipstock 1000 or 3000. The configuration of the lateral boreholes may be
based upon the at-
or-near real time interpretation of micro-seismic data or electromagnetic
imaging of an SRV.
[00329] In Figures 4E and 4MW, the whipstock 1050 and 3000 is disposed
below the lower
end of the outer conduit 490 of the external section 2000. The whipstock 1050,
3000 is presented
as having a generally 90 curvature. However, other degrees of curvature may
be desired such
that the jetting hose 1595 exits the casing 12 (or the outer sleeve 4100)
closer to the plane of
maximum principle (horizontal) stress, GH, of the host pay zone. Beneficially,
a larger-diameter
jetting hose 1595 may be used where the angle of curvature is less than 90 .
[00330] Note that in many cases, drillers will purposefully orient the
lateral sections of their
wellbores to be perpendicular to 0-H, which is typically parallel to the
minimum principle
(horizontal) stress, ch. As applied to the technology disclosed herein, a 90
casing exit by the
jetting hose 1595 should generate a lateral borehole in a direction
perpendicular to crh; i.e., along
the same trajectory that hydraulic fractures (in the absence of natural
fractures or other geologic
anomalies) tend to propagate within a rock matrix. Knowing this, the operator
can locate lateral
boreholes at a location along the horizontal leg 4c of the wellbore and in a
direction that is away
from an offset parent wellbore. Optionally, the operator can select a
whipstock face curvature
that will avoid a frac hit with an offset wellbore.
[00331] The hydraulic jetting assembly 50 also allows the operator to make
a 180 rotation
of the face 1050.1 of the whipstock 1000. This may be done, for example, if
the operator wishes
to align a subsequent UDP with (fh or if the operator wishes to increase SRV
while still avoiding
a frac hit.
[00332] It is also proposed herein that a mini-lateral borehole (such as
lateral borehole 522)
can control frac direction. As a first point, it is observed that the
hydraulic pressures used in
connection with forming a lateral borehole are typically lower than the
initial fracturing pressure
required to generate a parting of the formation. Thus, a lateral borehole can
be formed in a
direction away from an offset wellbore without creating a fracturing network
and the
accompanying risk of a frac hit. Thereafter, the lateral borehole could be
produced for a period
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of time, thereby weakening the rock matrix making up the pay zone ¨ again, in
a location away
from the offset wellbore. Stated another way, pre-frac depletion serves to
"magnetize" the lateral
borehole.
[00333] After a period of producing reservoir fluids, a formation
fracturing operation could
be conducted in the lateral borehole. In this instance, the fracture network
will not be biased to
flow in the direction of the parent wellbore but will form more closely in a
perpendicular
orientation off of the lateral borehole.
[00334] As long as the "weaker stress" points along the lateral borehole have
an initial fracture
pressure (PF, ) that is less than a formation parting pressure at the parent
wellbore (PFp) = 5,950
psi ), the fractures will propagate along the top and bottom of the lateral
borehole in a desired
direction that will not create a measurable risk of frac hit.
[00335] Because of the presence of the lateral borehole, initial formation
parting pressure (Ph)
and formation propagation pressure (PFp) in the rock matrix (at-or-near the
top and bottom of a
pre-frac lateral borehole) are reduced below the correlative (Ph) and (PFp)
thresholds extending
from the child well towards the parent. If necessary, combining the disruption
of the in situ
stress profile of the rock matrix surrounding the lateral borehole itself with
the compounding
PF1 and PFp reductions from near-lateral borehole depletion, (Ph) and (PFp)
(at-or-near the top
and bottom of the pre-frac lateral borehole) are then reduced below the
correlative (Ph) and
(PFp) thresholds extending from the parent wellbore.
[00336] As part of the method of avoiding frac hits herein, the operator will
need to determine
how long will it take to drain a sufficiently depleted volume surrounding the
lateral borehole,
and how much drained volume is required to create the desired pressure bias.
Answers to these
questions will be governed by numerous factors, chiefly those inherent to the
reservoir itself,
such as relative permeability's to the respective reservoir fluids.
[00337] One noteworthy practice in unconventional reservoirs development,
particularly
utilizing horizontal wellbores, is that many wells are drilled and cased long
before they are
perforated and fracked via multi-stage completions. This interim state is
referred to in the
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industry as drilled-but-uncompleted, with wellbores in this classification
simply referred to as
"DUC's". The procedure referenced above provides a methodology to utilize this
interim
"DUC" state to enhance the desired SRV geometry from subsequent fracs by first
partially
depleting reservoir volumes surrounding pre-frac lateral boreholes. Further,
given the right
reservoir parameters, the referenced procedure may even place an otherwise
idle DUC into a
cash flow positive position as oil and/or gas are produced via the pre-frac
lateral boreholes.
[00338] Referring back to the downhole hydraulic jetting assembly 50, Figures
2 and 4 depict
the final transitional component 1200, the conventional mud motor 1300, and
the (external)
coiled tubing tractor 1350. Along with the tools listed above, the operator
may also choose to
use a logging sonde 1400 comprised of, for example, a Gamma Ray ¨ Casing
Collar Locator
and gyroscopic logging tools.
[00339] Using the downhole hydraulic jetting assembly 50 described above, a
method of
avoiding frac hits is offered herein. In one aspect, the method first
comprises providing a child
wellbore 510 within a hydrocarbon-producing field 500. A portion of the child
wellbore 510
extends into the pay zone 530. Preferably, the wellbore 510 is completed
horizontally such that
a horizontal leg 514 of the child wellbore 510 extends along the pay zone 530.
[00340] The method also includes identifying a parent wellbore 550 within
the hydrocarbon-
producing field 500. In the context of the present disclosure, the parent
wellbore 550 is a well
located near or adjacent to the child wellbore 510. The parent wellbore 550 is
an existing older
well that was previously completed within the pay zone 530 such as shown in
Figures 5A and
5B.
[00341] Within a drainage volume affected by the parent wellbore,
production of reservoir
fluids has reduced pore pressure in the rock matrix. This reduction of pore
pressure has affected
the in situ stress profile of the rock matrix within the pay zone's pressure
sink. The result is that
the rock matrix will hydraulically fracture with significantly less
hydraulic/pressure force than
it otherwise would have at virgin conditions.
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[00342] Note that this reduction in formation breakdown pressure is
somewhat proportional
to the reduction in pore pressure. That is, the greater the drainage of pore
pressure of a specific
rock, the less the frac pressure required to initiate formation fractures; and
extend (or propagate)
fractures out into the formation. Accordingly, this pre-existing pore pressure
gradient within the
pay zone, upon the arrival and completion of the child wellbore, creates a
preferential "path-of-
least-resistance" for a hydraulic fracture initiating from a child wellbore
and extending towards
the vicinity of the parent wellbore.
[00343] The method further includes conveying a hydraulic jetting assembly
into the child
wellbore. The hydraulic jetting assembly is in accordance with the assembly 50
of Figure 2, in
any of its various embodiments. The hydraulic jetting assembly 50 is
transported into the
wellbore on a working string. Preferably, the working string is a string of e-
coil, that is, coiled
tubing carrying an electric line within, along the entirety of its length.
Even more preferably,
the working string is a string of coiled tubing having a sheath for holding
one or more electrical
wires and, optionally, one or more fiber optic data cables as presented in
detail in the '351 patent
incorporated above.
[00344] Generally, the hydraulic jetting assembly 50 will include:
a whipstock member having a curved face,
a jetting hose having a proximal end and a distal end, and
a jetting nozzle disposed at a distal end of the jetting hose.
[00345] The method also comprises setting the whipstock at a desired first
casing exit 521
location along the child wellbore 510. The face of the whipstock bends the
jetting hose
substantially across the entire inner diameter of the wellbore 510 while the
jetting hose is
translated out of the jetting hose carrier.
[00346] The method additionally includes translating the jetting hose out
of the jetting hose
carrier to advance the jetting nozzle against the face of the whipstock. This
is done while
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injecting hydraulic jetting fluid through the jetting hose and connected
jetting nozzle, thereby
excavating a lateral borehole within the rock matrix in the pay zone.
[00347] The method also includes further advancing the jetting nozzle
through a first window
at the first casing exit location 521 and into the pay zone 530. The method
then includes further
injecting the jetting fluid while further translating the jetting hose and
connected jetting nozzle
through the jetting hose carrier and along the face of the whipstock. In this
way, a first lateral
borehole 522 that extends at least 5 feet from the horizontal (child) wellbore
514 is formed.
[00348] In one aspect, the method of the present invention additionally
includes controlling (i)
a distance of the first lateral borehole 522 from the child wellbore 514, (ii)
a direction of the first
lateral borehole 522 from the child wellbore 514, or (iii) both, to avoid a
frac hit with the parent
wellbore 550 during a subsequent formation treatment operation. The formation
treatment
operation is preferably a formation fracturing operation, such as the frac
stage "n+1" of Figure
5B.
[00349] In one embodiment, the method further comprises monitoring tubing
and annular
pressures of the parent wellbore 550 while conducting frac operations of child
wellbore 510.
"Tubing pressure" typically means pressure within the production string of the
parent wellbore
550. "Annular pressures" would include pressure within a tubing-casing
annulus, but would also
include pressure in the annuli between casing strings. The later could perhaps
prove to be the most
ominous, as it could indicate issues concerning wellbore (and particularly,
casing) integrity, well
control, and even the exposure of fresh water zones to well and frac fluids.
[00350] The tubing and annular pressures are monitored to see if a so-
called pressure hit is
taking place in the parent wellbore 550 during any frac stage "n". Note that,
even if the parent
wellbore 550 is producing from a highly depleted portion 598 of pay zone 530,
the tubing-
production casing annulus pressure could be monitored, not only by a pressure
gauge at surface,
but by continuously shooting downhole fluid levels. Even if the surface gauge
is reading zero, an
increasing downhole fluid level could indicate that a pressure hit is
occurring within the parent
wellbore 550, and the operator could discontinue pumping frac fluid into child
wellbore 510.
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Alternatively, prior to pumping the subsequent frac stage, the operator will
jet lateral borehole 522
away from the parent wellbore 510. Alternatively still, the operator may
partially withdraw the
jetting hose and connected jetting nozzle from the first lateral borehole 522,
and then form a side
borehole off of the first lateral borehole 522 in order to create even more
SRV in a direction away
from the parent wellbore 550 to avoid a frac hit from frac stage "n+1".
[00351] The process of forming the first lateral borehole 522 in such a
manner as to avoid a frac
hit may be done during initial well completion. Alternatively, the process may
be done after the
child wellbore 510 has been producing hydrocarbon fluids for a period of time.
[00352] It is preferred, though not required, that the child wellbore 510
be completed
horizontally, referred to as a "horizontal wellbore." In this instance, the
first casing exit location
521 will be along a horizontal leg 514 of the child wellbore 510. In one
embodiment, the operator
will determine a distance of the parent wellbore 550 from the first casing
exit location 521 in
connection with avoiding a frac hit.
[00353] In one aspect, the method may further comprise the steps of:
retracting the jetting hose and connected nozzle from the first window (at the
first
casing exit location 521);
re-orienting the whipstock at the first casing exit location 521;
injecting hydraulic jetting fluid through the jetting hose and connected
nozzle,
thereby forming a second window at the first casing exit location 521;
advancing the jetting nozzle against the face of the whipstock while injecting
hydraulic jetting fluid through the jetting hose and connected jetting nozzle;
advancing the jetting nozzle through the second window at the first casing
exit
location 521 and into the pay zone 530;
further injecting the jetting fluid while advancing the jetting hose and
connected
nozzle along the face of the whipstock, thereby forming a second lateral
borehole 524 that
extends from the second window through a rock matrix in the pay zone 530; and
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controlling (i) a distance of the second lateral borehole (not shown) from the
child
wellbore 510, (ii) a direction of the second lateral borehole from the child
wellbore 510, or (iii)
both, to avoid a frac hit with the parent wellbore 550 during a subsequent
formation fracturing
operation in order to create SRV in the pay zone 530.
[00354] In this embodiment, the child wellbore 510 is preferably a
horizontal wellbore, and the
first casing exit location 521 is preferably along the horizontal leg 514. In
addition, the second
lateral borehole is preferably offset from the first lateral borehole 522 by
between 10-degrees and
180-degrees, and is thus not excavated in a horizontal orientation. In any
instance, the jetting fluid
typically comprises abrasive solid particles. The operator may then produce
hydrocarbon fluids
from both the first and second lateral boreholes.
[00355] In one embodiment of the method, the operator of the child wellbore
510 produces
reservoir fluids from the first and second lateral boreholes for a period of
time prior to pumping
fracturing fluids into the first and second lateral boreholes . In another
embodiment of the
method, particularly suited for settings of significant in situ stress
anisotropy (as in the case
where offset production from the subject pay zone has locally reduced pore
pressure) would be
to only jet a lateral(s) into the higher pressure / higher stress region of
the pay zone. That is, in
a direction opposite the source of depletion. Once completed, these laterals
could be produced
for a given time span prior to hydraulically fracturing, thus reducing the
pore pressures, and rock
stresses, in the vicinity surrounding the lateral boreholes. If the frac
treatments of these lateral
boreholes did not eventually break into a direction towards the original
depletion source,
subsequent lateral boreholes could be jetted in that direction, and then be
subsequently fracked.
Note in this case it would be advantageous to utilize a casing collar 4000 of
Figure 4MW, so
the portals exposing the original lateral boreholes could be closed off while
fracking the more
recent lateral boreholes.
[00356] It is understood that the operator may form a third or a fourth
lateral borehole (not
shown) proximate the first casing exit location 521. This allows an even
greater exposure of the
wellbore 514 to the surrounding pay zone 530. Confirmation of the directions
of the original
fractures could be detected in offsetting well pressures, through the use of
chemical tracers, or
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through micro-seismic data. Also, tiltmeter measurements in or near the child
wellbore 510 could
be employed.
[00357] In another embodiment of the method herein, the method may further
comprise:
retracting the jetting hose and connected nozzle from the first window (at the
first
casing exit location 521);
moving the whipstock to a desired second casing exit location along the
horizontal
leg 514 of the child wellbore 510, and setting the whipstock;
injecting hydraulic jetting fluid through the jetting hose and connected
nozzle,
thereby forming a second window at the second casing exit location;
advancing the jetting nozzle against the face of the whipstock while injecting
hydraulic jetting fluid through the jetting hose and connected jetting nozzle;
advancing the jetting nozzle through the second window at the second casing
exit
location and into the pay zone 530;
further injecting the jetting fluid while translating the jetting hose and
connected
jetting nozzle along the face of the whipstock, thereby forming a second
lateral borehole that
extends from the second window through the rock matrix in the pay zone 530;
and
controlling (i) a distance of the second lateral borehole from the child
wellbore 510,
(ii) a direction of the second lateral borehole from the child wellbore 510,
or (iii) both, to avoid
a frac hit with the parent wellbore 550 during a subsequent pumping of frac
fluid.
[00358] It is observed that in the illustrative wellbore 510, the second
lateral borehole could
be oriented vertically relative to the horizontal leg 514. In practice, the
second lateral borehole
may be oriented in any radial direction off of the horizontal leg 514. In
addition, the second
lateral borehole may extend any distance from the horizontal leg 514, provided
that regulatory
reporting requirements are met.
[00359] Once again, the child wellbore 510 is preferably a horizontal
wellbore, and the first
casing exit location 521 (and any second, third, or subsequent casing exits)
is preferably along
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the horizontal leg 514. The second casing exit location is preferably
separated from the first
casing exit location 521 by 15 to 200 feet. Preferably, each of the first 522
and second lateral
boreholes is at least 25 feet in length and, more preferably, at least 100
feet in length. In any
instance, the jetting fluid typically comprises abrasive solid particles. The
operator may then
produce hydrocarbon fluids from both the first and second lateral boreholes,
with or without
subsequent hydraulic fracturing.
[00360] In any of the above methods, advancing the jetting hose into a
lateral borehole is done
at least in part through a hydraulic force acting on a sealing assembly along
(such as at an upstream
end of) the jetting hose. Further, the jetting hose is advanced and
subsequently withdrawn without
coiling or uncoiling the jetting hose in the wellbore.
[00361] In one embodiment, advancing the jetting hose into a lateral
borehole is further done
through a mechanical force applied by rotating grippers of a mechanical
tractor assembly located
within the wellbore, wherein the grippers frictionally engage an outer surface
of the jetting hose.
[00362] In another embodiment, advancing the jetting hose into a lateral
borehole is
accomplished by forward thrust forces generated from flowing jetting fluid
through rearward thrust
jets located in the jetting assembly. These rearward thrust jets are
specifically located in the jetting
nozzle, or in a combination of the nozzle and one or more in-line jetting
collars strategically located
along the jetting hose. Preferably, the nozzle permits a flow of the jetting
fluid through rearward
thrust jets in response to a designated hydraulic pressure level. In this
instance, the flowing of
fluid through the rearward thrust jets is only activated after the jetting
hose has advanced into each
borehole at least 5 feet from the child wellbore. The additional rearward
thrust jets located in the
in-line jetting collar(s) are then activated at incrementally higher operating
pressures, typically
when the jetting hose has been extended such a significant length from the
child wellbore that the
rearward thrust jets within the nozzle alone can no longer generate
significant pull force to continue
dragging the full length of j etting hose along the lateral borehole.
[00363] In a related aspect, the method may include monitoring tensiometer
readings at a
surface. The tensiometer readings are indicative of drag experienced by the
jetting hose as lateral
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boreholes are formed. In this instance, the flowing of fluid through the
rearward thrust jets is
activated in each of the plurality of boreholes in response to a designated
tensiometer reading.
[00364] Of course, the operator will also monitor pressure readings at the
child wellbore.
During a hydraulic fracturing operation, a sudden drop in pumping pressure at
the surface indicates
fracture initiation. At this point, fluids flow into the fractured formation.
This means that a
formation parting pressure has been reached and that the fracture initiation
pressure has exceeded
the sum of the minimum principal stress plus the tensile strength of the rock.
[00365] Additional prophylactic steps to avoid a frac hit may be
undertaken. Such may include
monitoring tubing and/or annular pressures in the parent wellbore 550 or
conducting real-time
micro-seismic and/or tiltmeter measurements in or near the child wellbore 510
and extending to
(and preferably beyond) parent wellbore 550 and at least to any other directly
offsetting parent
wellbores in every direction. This will provide at least two benefits: (1)
provision of a precise
horizontal depth datum (particularly, as the jetting nozzle and hose just
begin to extend from the
child wellbore) with which to calibrate subsequently gathered micro-seismic
data; and (2)
confirmation of the path of the lateral borehole as it is being erosionally
excavated.
[00366] During a fracing operation, if monitoring indicates that an SRV has
failed to propagate
in the pay zone in any desired orientation emanating from the child well, then
the next stage's
configuration of lateral boreholes can be tailored to address the issues. For
example, a well plan
may be modified so that lateral boreholes in a subsequent stage may only be
formed in one
direction, rather than bilaterally. Alternatively, the lateral boreholes in a
subsequent fracturing
stage may be formed a longer distance in a direction away from an offset well,
and a shorter
distance in a direction towards the offset well.
[00367] Upon detecting propagation near a parent wellbore 550, the operator
can discontinue
the injection of the jetting fluid into the first lateral borehole, thereby:
(1) protecting the parent wellbore, its associated production, and future
recoverable
reserves it may still be able to capture;
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(2) saving the cost of associated frac fluids, proppants, and hydraulic
horsepower that
would be wasted while "hitting" or "bashing" the parent wellbore;
(3) precluding the expense of fishing the parent well's rods, pumps, tubulars,
tubing
anchor and other downhole production equipment that may become stuck due to
the influx of frac fluids and particularly, proppants from child well frac
operations;
(4) precluding the expense of a parent well cleanout operation, often
requiring coiled
tubing and nitrogen to circulate out frac fluids and proppants;
(5) precluding the cost of lost hydrocarbon production and (previously)
remaining
reserves attributable to the parent well, which is often the most significant
expense
of all; and
(6) precluding the expense of surface cleanup and remediation from an induced
"blowout" situation (note in the case where the parent wellbore is much older
(typically vertical) wells, and due to corrosion and aging may have weakened
and/or already have leaking casing, the "blowout" scenario could occur
entirely
underground).
[00368] Therefore in the subject method, no longer is the operator
superimposing a pre-
designed frac stage spacing, perforation densities, or even perforation
direction without
considering the frac behavior of the immediately preceding stage. By utilizing
the hydraulic jetting
assembly 50 and the methods presented herein, a given "cluster" (or set) of
lateral boreholes can
provide customization of (quite literally) far greater depths, wherein the
dual objectives of (1) SRV
maximization and (2) frac hits minimization can be achieved. Each grouping of
lateral boreholes
can be customized in terms of depth, direction, distance, design, and density
in preparation for
receiving a next frac stage. Where a ported custom collar 4000 is used, a
given borehole' s level
of depletion can also be increased to further enhance achievement of these two
main objectives.
[00369] Each of the UDP customization criteria is elaborated below:
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Depth
[00370] Because the apparatus can be set and re-set multiple times,
individual lateral boreholes
can be j etted through the casing and on out into the pay zone from any
position along the horizontal
wellbore. Further, even though the apparatus is conveyed via a string of
coiled tubing, because it
is configured to be able to conduct hydraulic fluid entirely throughout its
length, it can thus
incorporate and drive a downhole motor/CT tractor assembly toward its distal
end. Thus, the depth
limit is not that of the CT alone (e.g., to the point at which, while
advancing downhole, CT
"buckling" produces "lock-up"), but that depth to which a CT tractor can
convey the CT and the
apparatus. Note when utilizing ported custom collars, some of this depth
flexibility is lost because
the collars are run within the casing string itself. That is, the casing
collar portals that will provide
the casing exit location for a given lateral borehole is at a fixed,
predetermined wellbore depth
along the string of production casing. Notwithstanding this limitation,
multiple other lateral
boreholes may be jetted through the casing in conjunction with, or in place
of, lateral boreholes
jetting through the casing collars.
Direction
[00371] Lateral boreholes can be jetted in any axial direction (depending
on the tool assembly's
ratchet mechanism setting, typically within 5- or 10-degree increments) from
the wellbore.
Generally speaking, more and longer lateral boreholes are desired in the
direction for which
fracking is most difficult. Note that, typically, when utilizing the casing
collars herein, the
hydraulic locking swivels on each end will have been pressure-actuated to lock
the casing collars
in place when "bumping-the-plug" at the conclusion of the cement job of the
production casing
string. Hence, this employment of the casing collars carries with it the
inherent limitation of the
orientation of the exit portals relative to the self-orienting mechanism (that
is, the "weighted
belly"). That is, where the weighted belly will find true vertical at 180
(down), the exit portals
will have been milled at true horizontal (90 and 270 ), or perhaps some
slight variation to
correspond with the bedding plane of the pay zone. However, there is the
alternative method of
first engaging the casing collars with the whipstock of the jetting assembly
before they have been
locked, and using the whipstock' s orienting mechanism and tool-face
measurements to selectively
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set the casing collars (with their pre-milled port orientations) in any
desired orientation, then
pressuring-up on the CT-casing annulus to lock the casing collar in place.
(Note this would require
an uphole-to-downhole progression.) Thus, in the case where the tool
assembly's hydraulic
'pressure pulse' ratchet mechanism has been replaced with an electric driven
motor assembly,
coupled with real time tool face orientation, the operator at surface can
select any precise exit
orientation (at least, for one direction of exit ports) desired in real-time.
Notwithstanding any
initial orientation limitations imposed by the casing collar exit portals, in
a preferred embodiment
of the jetting assembly, the jetting nozzle and hose can be steered toward any
desired orientation
after exiting the wellbore.
Distance
[00372] Lateral boreholes may be generated that extend any distance from
the child wellbore,
limited only by the length of the jetting hose itself. This 'distance'
customization capability is also
available "on-the-fly" between frac stages.
Design
[00373] In certain embodiments, the subject apparatus is capable of
generating steerable lateral
boreholes. Though the maximum length of each lateral borehole is dictated by
the length of the
jetting hose, the ability to steer the jetting nozzle in 3-D space within the
pay zone provides for an
almost infinite number of geometries. Incorporated U.S. Patent No. 9,976,351
entitled "Downhole
Hydraulic Jetting Assembly." highlights this 'design' capability in
significant detail. Note that
this particular flexibility is independent of whether the initial casing exit
is obtained from jetting
through the casing or from utilizing portals in a casing collar. This is true
even if the casing collar
is of the self-orienting embodiment previously described, and has been
cemented into place. This
'design' customization capability is also available "on-the-fly" between
pumping frac stages.
[00374] The subject hydraulic jetting assembly 50 can generate lateral
boreholes at multiple
azimuths and at any given depth location. For this reason, the density of
lateral boreholes can be
highly customized.
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Depletion
[00375] Depletion of the pay zone in the vicinity around the circumference
of the lateral
borehole for a designated period of time can be useful in making the lateral
borehole a preferred
"path-of-least-resistance" for a subsequent frac stage. Optionally, selected
portals along a stage
that is considered to be high risk for a frac hit may be kept open for the
selected period of time for
production while other portals that are located along less-at-risk depths may
be closed.
[00376] Preferably, it will be the information observed from the
immediately preceding frac
stage that will guide design of a current lateral borehole. Of course, the
closer to real-time the data
feedback is to actual pumping times, the more frac fluids, proppant volumes,
pumping rates and
pressures can also be custom-tailored for each stage's already customized
lateral borehole(s).
[00377] The method disclosed herein also encompasses the deployment of
ported casing collars
within the production casing string. The casing collars serve as a substitute
for conventional perf
clusters in a child wellbore. The casing collars are run in conjunction with
pairs of hydraulic
locking swivels. The eccentric weighted belly's turns at approximately 180
from true vertical,
thus orienting all of the exit portals at or near true horizontal.
[00378] A benefit of the present methods and of the hydraulic jetting
assembly disclosed herein
is that lateral boreholes may be excavated within the pay zone without
creating fractures of any
significant scale. This means that, in many if not most cases, the operator
can favorably influence
the direction and distance of the growth of the fracture network (in the form
of SRV emanating
from the lateral boreholes) relative to the wellbore.
[00379] In one aspect of the present invention, lateral boreholes are
intentionally formed in a
horizontal direction. In addition, the horizontal leg of the wellbore is
drilled in a direction of least
principal (horizontal) stress, and the lateral boreholes extend "transverse"
to the wellbore
horizontally. This enables pumping pressures through the lateral boreholes to
be minimized since
rock stresses acting against the hydraulic forces will be minimized.
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[00380] Optionally, after a lateral borehole has been formed, the operator
may increase
pumping pressure up to the formation parting pressure. Fractures will then
emanate vertically, and
propagate horizontally in a vertical plane running parallel to the
longitudinal axis of the lateral
borehole itself.
[00381] It is observed that after a formation has parted, fractures will
begin to propagate. The
fracture propagation pressure of a formation (indicated at the fracture tip)
is typically less than the
original formation parting pressure. It is further observed that producing
reservoir fluids from the
pay zone 530 will change the stress regime in the rock matrix, and lower the
formation parting
pressure. Thus, in one aspect of the methods herein, the operator may choose
to produce reservoir
fluids from the lateral borehole(s) for a period of time before actually
injecting fluids into the
lateral borehole(s) at a pressure that exceeds the formation parting pressure.
In other words, the
operator may form the lateral boreholes, produce reservoir fluids from the
formation (causing a
reduction in pore pressure and a corresponding fracture propagation pressure),
and then inject
traditional proppant-laden fracturing fluids to create fracture networks.
[00382] In another aspect of the method, the well is completed with casing
collars 4000 and all
desired lateral borehole configurations are completed before commencing
formation fracturing
operations. The hydraulic jetting assembly 50 is the re-run into the hole with
the whipstock 3000.
This provides the operator with the ability to selectively close-off (or frac
and then re-close) portals
in the casing collars 4000 in any sequence desired.
[00383] Suppose, for example, real-time micro-seismic reveals the first
stage produced an SRV
highly skewed easterly. If the operator wanted to know if this characteristic
was going to continue
throughout the entirety of his, say, 100-stage well completion, instead of
proceeding from stage
#1 to #2, he may want to skip to stages 25, 50, 75, and 100, to learn east-
leaning tendency was
going to continue throughout. Say it does, and even increasingly so from toe-
to-heel, with
unacceptable westwardly SRV generation occurring by stage 75. Hence, instead
of completing
the remainder of the well after, say, stage 50, the operator may opt shut-down
frac operations at
that point, flow back the stages he has fracked, while simultaneously pre-
producing stages 51-100.
Notwithstanding this particular scenario, obviously, whatever the operator
observes form
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completing in stages sequence 1-25-75-100 will certainly influence his
planning, and validate
probable modifications of the completion plan.
[00384] Another aspect of the method, in the 1-25-50-75-100 stage sequence
scenario above,
revealing an increasingly heavy eastwards SRV generation, the operator (with
or without the pre-
frac production option afforded by completing with the casing collars 4000)
may want to utilize
the ability to steer the jetting nozzle 1600 and branch-off the existing
westerly lateral boreholes to
further enhance westerly SRV generation. Further, the operator may want to
actually frac through
one or more casing collars, first in a westerly direction (i.e., all portals
in position "3"), then shut
down briefly to re-shift the same casing collars into position "2" (east open,
only) or perhaps some
into position "4" (both east and west open).
[00385] In a still further aspect, steps may be taken to determine a
suitable period of time of
reservoir production to generate a change in in situ stresses before injecting
fracturing fluids and
forming the resultant fracture (SRV) network.
[00386] Once again, where a fracture network is formed, prophylactic steps
may be taken to
monitor pressure hits. Some degree of pressure change sensed in or caused to
the parent wellbore
550 may be beneficial. However, a frac hit where proppant invades the tubing
string of the parent
wellbore 550 or where a pressure in the parent wellbore exceeds burst pressure
ratings is to be
avoided herein.
[00387] In another aspect of the method of avoiding frac hits herein, the
operator of the parent
wellbore may take affirmative steps to prevent child well fracturing
interference. For example,
the operator may dump a heavy drilling mud into the well, creating hydrostatic
head that will act
against rising formation pressures during the fracturing operation in the
neighboring well.
Thereafter, the operator of the child well may turn off artificial lift
equipment (if it exists) and shut
in the well by closing off valves in the wellhead.
[00388] As an alternative, the operator of the parent wellbore may inject
an aqueous fluid into
the well and at least partially into the surrounding formation. This has the
effect of reversing the
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pressure sink that has been formed in the subsurface formation during
production, and minimizing
the "path of least resistance" created by changes in the in situ stress field
during production.
[00389] In a more aggressive aspect of protecting the child wellbore from a
frac hit, the operator
of the child wellbore may pump a diverting agent into the well. Diverting
agents are known and
may be used to redirect fluid flow away from one pay zone compartment already
thought to be
adequately stimulated, towards another compartment not yet adequately
stimulated. Divertants
can in some cases be used to block an established stimulation fluid's flow
path, and redirect the
fluid to an unstimulated (or under-stimulated) set of perforations. This
forced redirection improves
the stimulation treatment's efficacy and efficiency in the creation of
Stimulated Reservoir Volume
("SRV"), whether during the wellbore' s initial completion, a recompletion, or
remedial work.
[00390] In the present case, the operator is injecting a diverting agent
not for the purpose of
creating SRV, but to protect it. The diverting agent temporarily seals
perforations by creating a
positive pressure differential across perforations along the parent wellbore.
Halliburton' s
BioVertTM diverting agent is a suitable example. Once the diverting agent is
in place, surface-
generated back pressure can be held on the reservoir in the previously
completed parent well(s),
thus creating a pressure barriers or "halo" to the offset frac(s), thereby
avoiding frac hits from an
offset child well's completion/hydraulic fracturing operations. Once the
offset child frac
operations are complete, the diverting agent can be removed by dissolution or
by flowing the parent
well back.
[00391] Of course, the operator of the parent wellbore can also install a
bridge plug at the
bottom of the production tubing. In a more extreme case, the operator could
completely pull the
production tubing and associated artificial lift equipment.
[00392] In an alternate method of protecting the parent wellbore from a
frac hit, the parent
wellbore may be completed with the ported casing collars 4000 along its
production string. In this
case, the ported casing collars are not necessarily used in the parent
wellbore for jetting lateral
boreholes, although they certainly could be; rather, the ported casing collars
are provided in lieu
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of conventional or hydra-jet perforations. In other words, the ported casing
collars are serving as
"slotted base pipes," but wherein the slots may be selectively opened and
closed.
[00393] In the current method, the operator of the parent wellbore will
take the step of protecting
against a frac hit from an offset child well's frac by running a setting tool
having two spring-loaded
shift dogs 3201 and alignment blocks 3400. The setting tool may or may not be
the modified
whipstock 3000 as previously presented. Either way, the setting tool provides
for operating the
ported casing collars 4000 and setting them in a "closed" position. This
method, though protecting
only the parent wellbore, provides for mechanically sealing each port, and
thus precluding offset
frac fluids, or re-pressurized reservoir fluids, from entering the wellbore at
all.
[00394] Note that if additional protection out in the reservoir is desired,
the desired quantities
of a product like Halliburton's BioVert could be pumped out of each port just
prior to closing the
collars 4000. Otherwise, this method requires that no additional fluids be
introduced into the
parent wellbore.
[00395] It is acknowledged that this method would require pulling all rods,
pumps, and
production tubing to give the setting tool, e.g., whipstock 3000, full
wellbore access so it can
mateably engage with the casing collars for operation. Obviously, after the
threat of offset frac
fluid invasion passes, re-engaging the collar's sequentially, reopening them,
and re-running
production tubulars and equipment is required.
[00396] An additional method for completing a wellbore is also provided
herein. In this
method, the wellbore is a child wellbore having a horizontal leg. The wellbore
is being completed
in a hydrocarbon-bearing pay zone wherein a significant pressure gradient
exists across the pay
zone due to partial depletion of reservoir fluids and pressure in the vicinity
of a parent wellbore
offsetting the child wellbore. The depletion increases with proximity to the
parent wellbore.
[00397] As a result, a similar gradient of hydraulic fracturing initiation
and propagation
pressures also exists throughout the pay zone. The fracturing pressure
requirements generally
decrease with proximity to the parent wellbore. Therefore a placement of the
horizontal child
wellbore must transgress these pre-existing pressure/fracture gradients, such
that the pay zone on
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one side of the child wellbore will have weaker pressures and fracturing
thresholds (the "weak
side"), and the pay zone on the opposite side of the child wellbore will have
stronger pressures and
fracturing thresholds (the "strong side").
[00398] The method comprises:
hydraulically jetting a series of lateral boreholes from the horizontal leg of
the child
wellbore, wherein:
each of the lateral boreholes is formed only into the strong side of the pay
zone
relative to the child wellbore, such that a trajectory of each lateral
borehole is generally
towards ever increasing pressures and fracturing thresholds, and
each of the lateral boreholes is formed using a jetting nozzle and connected
jetting
hose,
producing reservoir fluids from the pay zone from each of the lateral
boreholes, thereby
weakening the rock matrix by the reduction of pore pressures and fracturing
thresholds on the
strong side;
after sufficient weakening has occurred, injecting fracturing fluids into the
horizontal
wellbore and into the lateral boreholes, wherein a pumping pressure of the
fracturing fluids initially
exceeds a fracture initiation pressure of the pay zone immediately proximate
to the lateral
boreholes, and subsequently exceeds a fracture propagation pressure of the pay
zone also
immediately proximate to the lateral boreholes; and
forming a plane of weakness intersecting the lateral borehole such that a
preferred initial
path for the fracturing fluids and a resultant SRV creation is along a
longitudinal axis of the lateral
borehole.
[00399] In connection with this method, the horizontal leg may be completed
to have the ported
casing collars 4000. The ported casing collars allow for "directional
depletion" into the strong
side, then re-closing the lateral boreholes on the strong side so that they
can be pressure-isolated
and subsequently fracked.
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[00400] It is finally observed that the downhole hydraulic jetting assembly
discussed herein and
the concepts provided may be used to maximize the SRV of a field within a
designated lease. In
this respect, the operator may form a series of UDP' s designed to extend to
"the four corners" of
a leasehold, thereby fulfilling the operator's duty of diligence to the
royalty owners or mineral
rights owners while operating within regulatory constraints of the state
commission.
[00401] It can be seen that an improved method for stimulating a subsurface
formation and
achieving the desired SRV for the production of hydrocarbon fluids while
avoiding frac hits in
neighboring wells has been provided. By avoiding frac hits, the operator is
spared the expense of
cleaning out or recompleting the parent wellbore. At the same time, the
operator has significantly
increased the Stimulated Reservoir Volume for the child wellbore without
harming adjacent parent
wellbores. In the unlikely event that the operator actually does "hit" a
neighbor's well, the operator
can demonstrate that an effort was made to control the propagation of
fractures by intentionally
directing lateral boreholes away from (meaning not in the direction of) or not
in the vicinity of the
neighboring parent wellbores.
[00402] It will be apparent that the inventions herein described are well
calculated to achieve
the benefits and advantages set forth above, it will be appreciated that the
inventions are
susceptible to modification, variation and change without departing from the
spirit thereof.
Improved methods for completing a child wellbore that avoids frac hits in
neighboring wells are
provided. In addition, a novel casing collar that may be mechanically
manipulated downhole to
selectively open and close portals that provide access to a surrounding rock
formation are
provided.
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