Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
IN SITU PUMP FOR DOWNHOLE APPLICATIONS
FIELD OF THE INVENTION
[002] The present invention relates, generally, to downhole apparatus and
methods usable for
penetrating into a formation from a wellbore. More specifically, the
embodiments of the present
invention relate to an in situ pump apparatus and methods for penetrating into
a formation and
releasing hydrocarbons contained therein.
BACKGROUND
[003] Hydraulic fracturing is used as a method to potentially increase
hydrocarbon production
in formations, such as sandstone, limestone, dolomite and shale. A well
operator performs the
following steps prior to hydraulic fracturing: First, the operator drills a
wellbore into the
formation and, then, he cases and cements the wellbore. Next, to gain access
to the formation,
the well operator blasts holes through the casing and cement using high
explosives--a process
called perforating. Then, to fracture the formation, the operator pumps high-
pressure fluid
through the perforations--typically gelled water or filtered hydrocarbons
laden with chemicals,
such as acids, surfactants, and proppants--into the wellbore to fracture the
formation under
immense hydraulic pressure.
[004] Concerns that hydraulic fracturing may contaminate ground water with
hydrocarbons
from the formation, and/or chemicals associated with the fracturing processes,
have recently
brought hydraulic fracturing under public and legislative scrutiny. A recent
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report in the Proceedings of the National Academy of Sciences, entitled Noble
gases
identify the mechanisms of fugitive gas contamination in drinking-water wells
overlying the Marcellus and Barnett Shales, by Thomas H. Darrah, et al. (vol.
111,
pages 14076-81, September 30, 2014, referred to herein as "the Darrah paper")
detailed various modes by which hydrocarbons, from hydraulically fractured
wells,
could escape into groundwater. That paper concluded that the primary mode of
contamination is via structural flaws in wellbore casing and cementing.
[005] Several of the modes discussed in the Darrah paper are shown in FIG. 1,
which
illustrates a well 100 extending into an area 101 of earth. Between the top
surface
layer 102 and the target formation (a.k.a., producing formation) 103, area 101
may
contain several other strata and formations. such as an aquifer 104 and
multiple
intervening formations 105 and 106. In a typical region of the Barnett shale
play in
north-central Texas, the target formation 103 may be about 6500-7500 feet
below the
surface, the aquifer 104 may typically be about 180-225 feet below the surface
(located in the upper Trinity Limestone), and the intervening formations 105
and 106
may be various layers of limestone (e.g., Marble Falls Limestone) or shale.
[006] The well 100 generally includes production tubing 107 extending into a
wellbore 108.
The wellbore 108 is typically cased with a casing string 109 that is cemented
to the
inner surface of the wellbore via a cemented annulus 110. Well 100 includes a
vertical section 111 and a horizontal section 112. Horizontal section 112
contains
fractures 113, as created by hydraulic fracturing.
[007] One possible route by which hydrocarbons produced from the target
formation 103
may access aquifer 104 is illustrated by arrows 114 and termed herein as a
"deformation route." Intervening formations may include deformations, such as
the
deformation 115, which can provide a route by which hydrocarbons, from the
target
formation 103, can travel to aquifer 104. When the formation is fractured
during
hydraulic fracturing, the generated fractures 113 may facilitate hydrocarbon
transfer
from the target formation 103 to deformation 115.
[008] A second possible route is illustrated as arrow 116 and is termed herein
an "annulus-
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conducted route." As shown in FIG. 1, the intervening formation 106 includes a
gas-
rich pocket 117 that is penetrated by the well 100. Any imperfections in the
cemented
annulus 110, i.e., cracks or sections that are not adequately sealed between
the
wellbore and the casing, can provide a route for hydrocarbons to travel from
the gas-
rich pocket 117 to the aquifer 104. Also, imperfections in the annulus that
extend into
the target formation 103 can also provide a route for hydrocarbons to escape
from the
formation 103 to the aquifer 104.
[009] Arrow 118 represents a third contamination route, in which contamination
occurs via
compromises in the casing 109. If the casing 109 is compromised with
structural
defects like cracks or holes, then hydrocarbons and fracturing fluids can
escape into
the aquifer 104 through those defects. That route is referred to herein as the
"casing
route." The Darrah paper concluded that the annulus conducted route 116 and
the
casing route 118 are primarily responsible for hydrocarbon contamination of
ground
water associated with the hydraulically fractured wells examined in that
paper.
[0010] Another problem with hydraulic fracturing is that it requires massive
amounts of
water--amounts measured in millions of gallons for a single well. Water is in
short
supply in many areas where hydrocarbon production occurs, and the high water
demand associated with hydraulic fracturing imposes a tremendous burden on
municipalities in those areas. Moreover, the well operator must install an
infrastructure for handling the water to be used for hydraulic fracturing, for
storing
that water, and mixing it with chemicals, such as acids, gels, foamers, foam
breakers,
salts, and other adjuvants. The spent fluids, which have been used for
hydraulic
fracturing, must also be stored, usually in large impoundment ponds, until the
fluids
can be remediated or disposed of.
[0011] The embodiments of the present invention provide in situ formation
enhancement
apparatus and methods, which are usable for penetrating into a formation and
releasing hydrocarbons contained therein, and which solve the problems
associated
with damage to the wellbore due to the use of explosives and contamination of
the
surroundings.
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SUMMARY
[0012] An apparatus for providing pressurized fluid, comprising a power source
body
configured to contain a gas-generating fuel, a tool body comprising a first
chamber
and a second chamber. The first chamber is configured to hold a fluid, and the
second
chamber is configured to receive gas from the gas-generating fuel within the
power
source body. The apparatus also includes a displacement member sealed between
the
first chamber and the second chamber and configured to stroke through the
first
chamber in response to a pressure increase within the second chamber, and a
hose
configured to generate a high-pressure jet of the fluid and to extend from the
tool
body, a diverter sub, or combinations thereof, when or after the displacement
member
is displaced or strokes through the first chamber for providing the
pressurized fluid.
[0013]The apparatus further comprises a valve configured to release the gas
from the second
chamber through the hose when the displacement member strokes or is displaced.
The
tool body comprises a first inside diameter and a second inside diameter
longitudinally disposed with respect to the first inside diameter, and the
second inside
diameter is greater than the first inside diameter when the displacement
member
strokes from the first inside diameter to the second inside diameter releasing
the seal
between the first chamber and the second chamber. One or more o-rings disposed
upon the displacement member form the seal between the first chamber and
second
chamber, and the seal is a gas-tight seal.
[0014] In certain embodiments, the apparatus further comprises an intake
coupling coupled to
the displacement member. The intake coupling comprises ports configured to
direct
the fluid in the first chamber to the hose when the displacement member
strokes. The
hose may comprise a jet-drilling nozzle for providing the pressurized fluid
into a
target formation. The diverter sub may be configured to direct the hose
laterally out
of the apparatus as the displacement member strokes through the tool body. The
fluid
may comprise a viscosity modifier, a surfactant, an acid, a proppant, abrasive
materials, gelled water, a bonding material, or combinations thereof.
[0015] The high-pressure jet of fluid, in certain embodiments, comprises fluid
that is
collected, filtered, stored, pressurized, or combinations thereof, from a
wellbore or a
surrounding formation while the apparatus is located at penetration zone of a
target
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formation. In certain embodiments, a length of the hose within the tool body
is at
least twice as long as a length of the hose within the diverter sub. The
displacement
member may be a piston that strokes through the first chamber for providing
the
pressurized fluid. The hose may be configured to be driven through a target
formation by the pressurized fluid, at least one nozzle on the hose, a
mechanical drive,
or combinations thereof.
[0016] The disclosed embodiments include an apparatus for jet-drilling a
downhole
production formation, comprising a tool body configured to be placed in a
cased and
perforated wellbore within the downhole production formation, at least one
chamber
within the tool body configured to contain a fluid, a piston initially
positioned at one
end of the at least one chamber and configured to stroke through a length of
the at
least one chamber, and a jet-drilling nozzle. The stroking of the piston
forces the
fluid through the jet-drilling nozzle and into the downhole production
formation.
[0017] In certain embodiments, the piston is configured to enable a release of
high-pressure
gas into the downhole production formation after the fluid is forced into the
downhole
production formation. The jet-drilling nozzle can be removed from the
apparatus prior
to the release of the high-pressure gas. The jet-drilling nozzle may be
configured to
be removed from the apparatus by passing a solid material through the hose,
passing a
metallic material through the hose, passing an acid through the hose, or
combinations
thereof. The jet-drilling nozzle may comprise any number of orifices, any size
of
orifices, any configuration, and any shape of orifices for forcing the fluid
into the
downhole production formation.
[0018] The apparatus may include a number of orifices on the jet-drilling
nozzle, sizes of the
orifices on the jet-drilling nozzle, a ratio of the number of orifices on a
leading edge
to the number of orifices on a trailing edge of the jet-drilling nozzle that
controls
pressure of the pressurized fluid, a forward travel rate of the jet-drilling
nozzle, and a
cutting or perforating penetration of the jet-drilling nozzle. The chamber may
be
configured to contain the drilling fluid used for jet-drilling, and a second
chamber
may be configured to contain the fuel used to pressurize the jet-drilling
performed by
the apparatus within the wellbore.
[0019] The disclosed embodiments also include a method of generating a jet of
high pressure
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fluid within a wellbore. The method comprises activating a gas-generating fuel
contained within a fuel chamber of a downhole tool to produce an expanding
gas,
pressurizing a gas-expansion chamber of the downhole tool with the expanding
gas,
and stroking a displacement member through a fluid chamber configured to hold
a
fluid. The displacement member strokes due to pressurizing of the gas-
expansion
chamber and causes pressurizing of the fluid. The method also includes jetting
the
fluid out of an outlet of the downhole tool in response to the pressurizing of
the fluid,
and the jetting of the fluid creates a bore in a production formation
surrounding the
wellbore.
[0020] The step of creating the bore comprises extending a hose into the bore
to enlarge the
bore for forcing the fluid into the production formation, wherein the hose
extends into
the bore from a tool body, a diverter sub, or combinations thereof. The method
further comprises removing a jet-drilling nozzle from the outlet prior to
releasing the
expanding gas by passing a solid material through the hose, passing a metallic
material through the hose, passing an acid through the hose, or combinations
thereof.
[0021] The method further comprises stimulating the production formation by
releasing the
expanding gas from the outlet after the fluid has been jetted. Releasing the
expanding
gas comprises releasing the expanding gas through a valve in the displacement
member, releasing the expanding gas around the displacement member, or
combinations thereof. The method further comprises performing well logging to
produce logging data for identifying a target formation to create the bore and
using
the logging data to position the downhole tool at the target formation for
creating the
bore. The method further comprises using the logging data for re-entry of the
downhole tool or a second downhole tool at prior target formation or the bore.
[0022]The method further comprises the method steps of deploying a positioning
tool within
a wellbore at a site of a target formation, wherein the positioning tool
comprises a
selective profile, and latching the downhole tool into the positioning tool,
wherein the
downhole tool comprises a profile complementary to the selective profile of
the
positioning tool for positioning the downhole tool at the target formation.
The
method further comprises using logging data, the positioning tool, or
combinations
thereof for re-entry of the downhole tool or a second downhole tool at prior
target
formation or the bore. The displacement member may be a piston or a crush
cylinder.
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[0023] A method of generating a jet of high pressure fluid within a wellbore,
comprises
activating a gas-generating fuel contained within a fuel chamber of a downhole
tool to
produce an expanding gas, pressurizing a gas-expansion chamber of the downhole
tool with the expanding gas, and stroking a piston through a fluid chamber
configured
to hold a fluid. The piston strokes due to pressurizing of the gas-expansion
chamber.
The method also comprises jetting the fluid out of an outlet of the downhole
tool in
response to the stroking of the piston. The jetting of the fluid creates a
bore in a
production formation surrounding the wellbore
BRIEF DESCRIPTION OF THE DRAWINGS
[0024] FIG. 1 illustrates modes of groundwater contamination associated with
hydraulic
fracturing.
[0025] FIG. 2 is a flowchart illustrating a method of stimulating a formation.
[0026] FIG. 3 illustrates an in situ formation enhancement tool, as described
herein.
[0027] FIG. 4 illustrates a piston and fluid intake coupling, as used in
embodiments of an in
situ formation enhancement tool, as described herein.
[0028] FIGS. 5A-5D illustrate embodiments of a jet-drilling nozzle.
[0029] FIG. 6 illustrates implementation of a jet-drilling nozzle.
[0030] FIG. 7 illustrates a configuration for bleeding gasses from within an
in situ formation
enhancement tool, as described herein.
[0031] FIG. 8 illustrates an alternative configuration for bleeding gasses
from within an in
situ formation enhancement tool, as described herein.
[0032] FIGS. 9A and 9B illustrate an invaded zone of a wellbore.
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[0033] FIG. 10 illustrates formation damage caused by hydraulic fracturing.
[0034] FIG. 11 illustrates an embodiment of an apparatus for generating a high-
energy
impulse using a gas-generating fuel.
[0035] FIG. 12 illustrates an embodiment of an in situ formation enhancement
tool, having a
long stroke length.
[0036] FIGS. 13A and 13B illustrate an embodiment of an in situ formation
enhancement
tool, having a telescoping hose.
[0037] FIGS. 14A and 14B illustrate an embodiment of an in situ formation
enhancement
tool, having a piston governing system using linear bearings to impede the
stroking
speed of the piston.
[0038] FIG. 15 illustrates an embodiment of an in situ formation enhancement
tool containing
jet-drilling fluids having different compositions.
[0039] FIG. 16 illustrates an embodiment of an in situ pump powered by an
electric motor.
DESCRIPTION
[0040] Before describing selected embodiments of the present disclosure in
detail, it is to be
understood that the present invention is not limited to the particular
embodiments
described herein. The disclosure and description herein is illustrative and
explanatory
of one or more presently preferred embodiments and variations thereof, and it
will be
appreciated by those skilled in the art that various changes in the design,
organization,
means of operation, structures and location, methodology, and use of
mechanical
equivalents may be made without departing from the spirit of the invention.
[0041] As well, it should be understood that the drawings are intended to
illustrate and
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plainly disclose presently preferred embodiments to one of skill in the art,
but are not
intended to be manufacturing level drawings or renditions of final products
and may
include simplified conceptual views to facilitate understanding or
explanation. As
well, the relative size and arrangement of the components may differ from that
shown
and still operate within the spirit of the invention.
[0042] Moreover, it will be understood that various directions such as
"upper", "lower",
"bottom", "top", left", "right", and so forth are made only with respect to
explanation in conjunction with the drawings, and that components may be
oriented
differently, for instance, during transportation and manufacturing as well as
operation.
Because many varying and different embodiments may be made within the scope of
the concept(s) herein taught, and because many modifications may be made in
the
embodiments described herein, it is to be understood that the details herein
are to be
interpreted as illustrative and non-limiting.
[0043] Explosively perforating a casing and cemented annulus of a wellbore as
a precursor to
hydraulic fracturing can contribute to groundwater contamination by causing
cement
damage and weakening of the casing-to-cement bond and the cement-to-formation
bond. Cement damage can cause routes for hydrocarbons and fracturing fluid to
escape from a hydrocarbon formation into the groundwater. Deluging the
formation
with massive amounts of fluid from the surface of the wellbore, as in
hydraulic
fracturing, can also compact the formation and trap large quantities of
interstitial
hydrocarbons, preventing extraction of those hydrocarbon deposits.
[0044] The in situ formation enhancement tool, described herein, addresses
these problems.
The in situ formation enhancement tool uses jets of high-pressure fluid, such
as water
or hydrocarbon, to bore into the formation. The fluid is carried downhole
within the
in situ formation enhancement tool rather than pumped downhole from the
surface, as
it is in hydraulic fracturing. The mechanism and fuel for pressurizing the
fluid is also
self-contained within the in situ enhancement tool.
[0045] FIG. 2 provides a flowchart overview of a method 200 for implementing
the in situ
enhancement tool described herein from the surface of a wellbore. First, to
determine
9
an effective location for implementation of the in situ enhancement tool, a
well operator may
perform one or more well logging steps 201 to identify regions of a well
likely to produce
hydrocarbons. Many well logging methods are known in the art, and it is within
the ability of a
person of skill in the art to decide which logging methods are appropriate for
their given
situation. Logging may be performed while drilling by incorporating sensors
into the drilling
string used to drill the well or by analyzing the drilling mud and formation
cuttings that return to
the surface during drilling. Logging may be performed after drilling by
lowering logging tools
into the wellbore via a wireline. Logging data may be based on one or more of
many different
observable properties of the formations within the well, including
resistivity, acoustic properties,
density, the interaction of the formation with radiation of different types,
etc. By logging the
well, the well operator seeks to identify where geological formations, which
are likely to produce
hydrocarbons, are located within the well. Those are the locations that the
operator may choose
to stimulate using the methods described herein.
[0046] Having identified a promising formation (target formation) within the
wellbore, the
operator can position the in situ enhancement tool within the wellbore, within
that target
formation, or within a nearby formation, any of which may be located thousands
of feet from the
surface hole of the wellbore. Moreover, it may be beneficial for an operator
to perform multiple
operations with multiple tools. For multi-run operations, an operator may
position the equipment
within the target formation, trigger the operation, bring the equipment to the
surface, and
subsequently re-enter and reposition the equipment or other equipment in the
same exact position
within the target formation. The positioning, in addition to the re-entry and
repositioning of the
downhole tool and other equipment may be accomplished by using the Tool
Positioning and
Latching System described by MCR Oil Tools, LLC. and disclosed in U.S. Patent
Application
Pub. No. 2015-0184476, filed Nov. 24, 2009. In addition, or alternatively, the
positioning, re-
entry, and repositioning of the downhole tool and other equipment may be
accomplished by
using the Permanent or Removable Positioning Apparatus and Methods for
Downhole Tool
Operations described by MCR Oil Tools, LLC and disclosed in U.S. Patent
Application Pub. No.
2013/0025883, filed July 24, 2012.
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With regard to the positioning and latching systems of MCR Oil Tools, LLC, the
well logging
may be performed to identify the target formation, and then the downhole tool
(i.e., in situ
formation enhancement tool) can be deployed with the use of the positioning
tool 202. The
operator can deploy the positioning tool 202 within the wellbore, typically
placing the apparatus
a few feet below the exact target position within the wellbore, to allow the
operator to reliably
reposition the enhancement apparatus at the target. As discussed above, U.S.
Patent Application
Publication No. 2013/0025883, describes and discloses the downhole positioning
tool provided
by MCR Oil Tools, LLC, which can be used to reproducibly position the
enhancement apparatus
within the target formation. Briefly, the positioning tool described in that
application features a
slip system for anchoring the positioning tool within a wellbore and a system
of grooves for
interfacing with complimentary protrusions on a downhole tool, or vice versa,
such as the
enhancement apparatus described herein. Once anchored, the positioning tool
allows the
enhancement apparatus to be reproducibly deployed to the same location within
the wellbore.
As an alternative to the positioning tools described above, any MCR Oil Tools,
LLC anchoring
systems can be used for positioning the downhole tool at the target formation.
[0047] Once the positioning tool is anchored within the wellbore, the operator
uses the in situ
enhancement tool or a torch to cut or perforate a hole in the casing 203.
Cutting or perforating
through the casing enables the enhancement apparatus to perform operations on
the cemented
annulus and the formation without explosively perforating the casing (and
damaging the
surrounding cement). Examples of suitable torches for cutting or perforating
the casing are
provided by MCR Oil Tools, LLC, and described in U.S. Patent Nos. 6,186,226,
7,690,428, and
8,020,619. Specific examples of suitable torches include MCR's Perforating
Torch CutterTM tool
or MCR's Perforating Pyro Torch tool, both available from MCR Oil Tools
(Arlington, Texas).
Once the torch is in position, the operator activates the torch to cut or
perforate a hole in the
casing. According to some embodiments, the torch may cut or perforate a single
hole in the
casing. In other embodiments, the torch may be configured to cut or perforate
multiple holes in
the casing. For example, the torch may be configured to cut four holes in the
casing, each hole at
the same depth and spaced 90 from each other about the inside diameter of the
casing.
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[0048] With one or more holes cut in the casing and the cemented annulus
exposed to the
inside of the wellbore, the operator can remove the torch or the in situ
enhancement
tool from the wellbore and deploy the next in situ enhancement tool into the
wellbore.
The in situ enhancement tool is described in detail below. Like the torch, the
in situ
formation enhancement tool can be configured to interface with the downhole
positioning tool, allowing the in situ formation enhancement tool to align
with the
hole(s) in the casing.
[0049] Once aligned with the hole, the operator activates the in situ
formation enhancement
tool. When the in situ formation enhancement tool receives an activation
signal (e.g.,
a countdown finishing, a specific condition reached, or a wireless or wired
signal sent
to the in situ formation enhancement tool), the in situ formation enhancement
tool
uses high-pressure jets of fluid to bore 204 through the cement and into the
formation.
The fluid is pressurized within the in situ formation enhancement tool by
compressing
the fluid. Compression of the fluid may be accomplished in a number of ways
including using a non-explosive gas-generating fuel that is also contained
within the
in situ formation enhancement tool, an electro-mechanical pump, a spring-
loaded
piston, or other chemical, mechanical, or electrical pressurizing apparatus.
As
explained in more detail below, a quick way of pressurizing the fluid may be
to use
gas generated by burning fuel within the in situ enhancement tool to actuate
the piston
that compresses the fluid. The fuel that is burned can include such
characteristics as
having a selected mass flow rate, a selected burn rate, or combinations
thereof, which
can be adapted to create the amount of pressure needed to displace the piston
within
the downhole tool. The type of fuel selected for use can be dependent upon
such
characteristics as the hydrostatic pressure between the tool body and the
target
formation, the temperature at the cutting or perforation site, presence or
lack of
circulation within the wellbore, and other conditions relating to the wellbore
and/or
the target formation. Specifically, in an embodiment, the fuel of the downhole
tool
can be configured to provide a desired mass flow and/or burn rate, e.g.,
through use
and relative orientation between different fuel types, and/or fuel sources
having
differing shapes or physical geometries. The mass flow and/or burn rate can be
selected based on various wellbore conditions, the thickness of the casing
and/or
target formation to be perforated or cut, such that a bore through the casing
and/or
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target formation can be efficiently formed, without any contamination or
damage to
the surrounding areas. In calculating the amount of fuel required for forming
the bore
through the casing and/or the target formation, an additional quantity of fuel
may be
required to generate the expulsion and removal of the cuttings of the casing,
tailings
of the cement, or other debris formed through the cutting and/or perforating
of the
bore. As such, the amount of fuel is calculated, and the type of fuel is
selected for not
only generating the pressure needed for penetration of the casing and/or
target
formation in forming the bore, but also for removal of the cuttings, tailings,
and other
debris generated by the cutting and perforating of the casing and/or the
target
formation.
[0050] An electromechanical pump (e.g., electromechanical rotating pump,
diaphragm pump,
etc.) may also be used to drive the piston through a fluid-storage chamber.
The
stroking piston forces the fluid through an extending hose and, in some
embodiments,
through a jet nozzle, which can bore into the formation. The in situ formation
enhancement tool can drill a lateral bore several feet into the formation, for
example,
about 2 to about 20 feet. The lateral bore may be about one (1) centimeter
(0.394
inches) to about five (5) centimeters (1.968 inches) or more in diameter.
[0051] If multiple holes were cut or perforated into the casing using the
torch in step 203,
then the operator may retrieve the in situ formation enhancement tool, reset
the tool,
and send the in situ formation enhancement tool back into the formation to
drill
another lateral bore. Again, the positioning tool, set in step 202, can
facilitate this
resetting and redeployment process by enabling the operator to reliably
position the in
situ formation enhancement tool at the proper location within the wellbore,
i.e., where
the torch perforated the casing. Once so positioned, the in situ formation
enhancement tool can drill another lateral bore, repeating the sequence
described in
step 204.
[0052] At step 205, the formation is stimulated by subjecting the surface area
of the one or
more lateral bores extending into the formation to a high-energy impulse.
According
to one embodiment, the in situ formation enhancement tool can generate the
high-
energy impulse. Alternatively, the operator may retrieve the in situ formation
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enhancement tool from the wellbore and deploy a pulse-generating tool into the
wellbore for generating a high-energy impulse. An example of a pulse-
generating
tool is described in more detail below. It uses a gas-generating fuel to
generate high-
pressure gas and then quickly releases that high-pressure gas to generate a
high-
energy pulse. The high-energy pulse transmits through the fluid within the
lateral
bores and impacts the surface of the formation within the lateral bores,
causing the
formation to crumble and release interstitial hydrocarbon.
[0053] Following stimulation using the high-energy pulse, the formation is
typically allowed
to produce for some length of time. Typical lengths of time can range from a
few
weeks to a few years. A specific example is about six months. At step 206, the
well
production is monitored, and the well operator may repeat the steps of method
200 if
the amount of produced hydrocarbons slows or drops off.
[0054] FIG. 3 illustrates an embodiment of an in situ formation enhancement
tool 300. The
illustrated tool has the following primary sections: isolation sub 301, power
source
body 302, bleed sub 303, tool body 304, and placement sub 305. Other
embodiments
may include additional or alternative sections, including mechanical or
electromechanical pumps, springs, or other fluid-pressurizing machines,
apparatuses,
or methods.
[0055] Isolation sub 301 connects the in situ formation enhancement tool 300
to a
conveyance mechanism. The conveyance mechanism is typically a slickline, c-
line,
workover string, or the like. Isolation sub also contains an activating
mechanism 306
for activating power source 307 (described in more detail below). Examples of
suitable activators include Series 100/200/300/700 Thermal GeneratorsTm
available
from MCR Oil Tools, LLC, located in Arlington, Texas.
[0056] In operation, the power source body 302 contains a power source 307
that is capable
of producing gas in an amount and at a rate sufficient to pressurize and
operate tool
300. Power source 307 may be considered an "in situ" power source or fuel,
because
it is situated downhole during operation instead of on the surface. In situ
power
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generation has the advantage that little, if any, communication is required
between in
situ formation enhancement tool 300 and the surface to pressurize the tool.
[0057] Examples of suitable power source materials are provided by MCR Oil
Tools, LLC, as
described in U.S. Patent No. 8,474,381, issued July 2, 2013, the entire
contents of
which are hereby incorporated herein by reference. Power source materials can
include or utilize thermite or a modified thermite mixture. The mixture can
include a
powdered (or finely divided) metal and a powdered metal oxide. The powdered
metal
can be aluminum, magnesium, etc. The metal oxide can include cupric oxide,
iron
oxide, etc. A particular example of thermite mixture is cupric oxide and
aluminum.
When ignited, the flammable material produces an exothermic reaction. The
material
may also contain one or more gasifying compounds, such as one or more
hydrocarbon
or fluorocarbon compounds, particularly polymers.
[0058] The power source 307 is contained within a fuel chamber 302a of the
power source
body 302. Once activated, the power source 307 generates gas, which can expand
and
fill the fuel chamber 302a. The gas can expand through a conduit 303a of the
bleed
sub 303 and can impinge on a piston 308, which is contained within the tool
body
304. Under the pressure of the impinging gas, the piston 308 moves (i.e.
strokes) in
the direction indicated by arrow 309, within a fluid chamber 304a of the tool
body
304.
[0059] The fluid chamber 304a contains a fluid (e.g., hydraulic fracturing
fluid), which
becomes pressurized under the pressure generated by the piston 308 as the
piston
strokes. The fluid, in certain embodiments, is stored within the fluid chamber
304a at
the surface of the wellb ore and travels with the in situ enhancement tool 301
to the
production formation. In other embodiments, the fluid may be collected,
filtered,
stored, and/or pressurized from the formation while the in situ enhancement
tool is
located at the formation. That is, the in situ enhancement tool may use
surrounding
fluid, even production fluid for example, to pressurize and jet out of the in
situ
enhancement tool to create a bore. As shown in FIG. 3, the piston 308 is
coupled to a
hose 310 via an intake coupling 311. The piston 308, intake coupling 311, and
hose
310 are shown in more detail in FIG. 4 and discussed in more detail below.
Here, it
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need only be understood that the fluid in the fluid chamber 304a is forced
into the
hose 310 through the intake coupling 311 and flows through the hose under very
high
pressure.
[0060] As the hose 310 is pushed downward in the direction indicated by arrow
309, the hose
310 is fed through a diverter sub 312 that is within the tool body 304. The
diverter
sub 312 deflects the hose 310 so that the hose 310 is pushed out of the tool
body 304
through an opening 313. A dashed hose 310a in FIG. 3 illustrates the hose
being
pushed out of the in situ formation enhancement tool 300. The hose
310 can be
capped with a nozzle 314, and the nozzle 314 can be used to generate a high-
pressure
jet for jet drilling into the cemented annulus and the formation, as explained
in more
detail below.
[0061] FIG. 4 illustrates the piston 308 mid-stroke as it strokes within the
tool body 304. The
piston 308 includes o-rings 308a, which can form a gas-tight seal between the
piston
308 and the inside diameter of the tool body 304. The piston 308 may be made
of
steel and can include grooves for containing the o-rings 308a.
[0062] The gas-expansion chamber 304b, shown in FIG. 4, can be filled with gas
generated
by the power source 307, as illustrated in FIG. 3. As the power source
continuously
generates gas, the pressure within the chamber 304b can increase and continue
to push
the piston 308 in the direction indicated by the arrows 401.
[0063] The fluid chamber 304a can contain fluid that is used to jet drill into
the cased
annulus and formation. As the piston 308 strokes, the fluid in the fluid
chamber 304a
is forced into the ports 402 of the intake coupling 311, as indicated by the
arrows 403.
The fluid is further forced through the hose 310 in the direction indicated by
the
dashed arrows 404.
[0064] The fluid can be tailored to the particular application and to the
formation to be
drilled. For example, the fluid may be acidic for drilling through acid-
soluble cement
and strata. The fluid may include viscosity modifiers, surfactants, acids such
as
hydrochloric acid (e.g. 15 %) or a combination of hydrochloric and
hydrofluoric acid
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(12% / 3%, e.g.), proppants, and/or abrasive materials, gelled water, or a
bonding
material such as waterglass. As mentioned above, the fluid may also be
collected and
filtered from fluid surrounding the in situ enhancement tool 301.
[0065] The intake coupling 311 can be milled from steel to provide an internal
flow path
from the ports 402 to the hose 310. However, other materials can be used, such
as
durable, pressure resistant plastics or ceramics. The hose 310 can be coupled
to the
intake coupling 311 using a threaded connector 320, or generally any connector
known in the art. The hose 310 can be a high-pressure hydraulic hose capable
of
sustaining high pressures. Before the hose 310 extends from the opening 313,
however, the pressure inside of the hose 310 is the same as the pressure
within the
fluid chamber 304a. Therefore, for the section of hose 310 that remains within
the
fluid chamber 304a, there is a no significant pressure differential between
the volumes
inside of the hose (e.g., arrows 404) and outside of the hose 310 (e.g.,
arrows 403).
[0066] As the piston 308 strokes, the fluid is forced through the hose 310 and
out of the
nozzle 314. FIGS. 5A-5D illustrate embodiments of the hose 310 and the nozzle
314.
The nozzle 314 can be connected to the hose 310 by a threaded connection 501,
as
shown in FIG. 5C for example. The nozzle 314 comprises a leading edge 314b and
a
trailing edge 314c, which are illustrated in FIGS. 5B and 5C, respectively.
FIG. 5D
illustrates a perspective view of nozzle 314. Both leading edge 314b and
trailing edge
314c include orifices 502 for discharging jets of fluid which are shown in
FIGs. 5B,
5C, and 5D.
[0067] FIG. 6 illustrates how the nozzle 314 drills a lateral bore 600. Fluid
601 jetting out of
the orifices on the leading edge of the nozzle 314 can drill into the
formation 602 (or
into the cemented annulus) while fluid 603 jetting out of the trailing edge
helps propel
the nozzle forward. The total number of orifices, the placement of the
orifices, the
sizes of the orifices and the ratio of numbers of orifices on the leading edge
and the
trailing edge can be sized to control the pressure (choke) of the fluid, the
forward
travel rate of the nozzle, and the cutting or perforating penetration of the
nozzle. In
certain embodiments of the nozzle 314, there are between 1 to about 6 orifices
on the
leading edge and between about 3 to about 12 orifices on the trailing edge.
The
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orifices 502, in certain embodiments, may be about 0.07 millimeters (0.0028
inches)
to about 1.5 millimeters (0.059 inches) in diameter. In other embodiments, the
orifices 502 may include other sizes or shapes, including oval, square,
rectangular, or
other shapes to form a jet for fracturing the formation. While the nozzle 314
illustrated in the embodiments of FIGS. 5A-D and FIG. 6 is cylindrical, the
nozzle
314 may have a different shape, such as conical or spherical, and may include
orifices
502 formed on other sides and/or faces of the nozzle 314.
[0068] Once the hose 312 has been fully extended into the formation, the gas
expansion
chamber 304b (FIG. 4) will typically still contain an amount of highly
pressurized gas
that needs to be bled out of the chamber before returning the in situ
formation
enhancement tool 300 to the surface. According to some embodiments, the
residual
high-pressure gas can be vented into the lateral bore, generating a high-
energy pulse
that stimulates the formation. One configuration for venting the high-pressure
gas is
illustrated in FIG. 7. As the piston 308 moves within the chamber 304b, o-
rings 308a
form a gas-tight seal between the piston 308 and the inside diameter (I.D.) of
chamber
304b. To vent the gas, the tool body 304 can include a section 304c having an
enlarged I.D. so that, when the piston is within that section, the o-rings no
longer form
a gas-tight seal. So as the intake assembly 311 comes to rest at the bottom of
section
304c, pressurized gas within the gas expansion chamber 304b can pass into the
section 304c via an interface 701 between the piston and the I.D. of the tool
body 304.
Then, the pressurized gas can escape from the section 304c via the intake
coupling
ports 402, and the pressurized gas can escape into the formation via the hose
310.
[0069] FIG. 8 illustrates an additional embodiment of a configuration for
venting high-
pressure gas from within the chamber 304b. According to that embodiment, the
piston 308 is configured with a plug valve 801. The plug valve 801 is closed
while the
piston is stroking, isolating the gas-generation chamber 304b from the fluid
chamber
304c. As the piston 308 strokes, however, a bottom portion 801a of the plug
valve
801 contacts the bottom of the fluid chamber 304c (indicated by the dashed
line). The
contact forces the plug member 801b out of the orifice 801c, thereby opening
the plug
valve 801. When the plug valve 801 opens, pressurized gas within the gas-
generation
chamber 304b can pass into the fluid chamber 304c. The pressurized gas can
then
escape into the formation via intake coupling ports 402 and the hose 310.
Other valve
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types known in the art may also be capable of opening when the piston
completes its
stroke. Moreover, multiple valves may be used on a single piston 308.
[0070] Venting the pressurized gas is a safety precaution; a highly
pressurized container
could be dangerous to open at the surface. Moreover, releasing the pressurized
gas
before retracting the tool provides other advantages--the release of the
pressurized gas
downhole generates an impulse that can stimulate production within the
formation.
[0071] Referring again to FIG. 6, arrows 601 and 603 represent streams of
fluid jetting out of
the orifices on the nozzle 314. Stimulating the formation occurs after the
piston 308
of the in situ formation enhancement tool 301 has completed its stroke. At
that point,
the bore 600 is filled with fluid and no more fluid is jetting from the
nozzle. The
remaining pressurized gas within the tool is released passed the piston 308
and into
the hose, as explained above. The arrows 601 and 603 can also represent highly
pressurized gas that is being released into the lateral bore 600 and into the
formation
602 during stimulation. The highly pressurized gas can create an impulse
through the
fluid within the bore 600 and can permeate the formation 602 at the interface,
and
dissipate the gas volume into the micro-fissures of the formation 602 and the
bore
600, thereby enlarging the micro-fissures and stimulating the release of
hydrocarbons
that are entrapped within interstices of the formation matrix.
[0072] Subjecting the jet drilled lateral bore to an intense pulse of
compressed gas is more
effective than traditional hydraulic fracturing for several reasons. One
advantage is
that the lateral bore provides access to virgin formation, that is, a region
of the
formation that has not been penetrated by drilling mud and drilling mud
filtrate when
the wellbore was drilled. FIGS. 9A-B illustrate a mud-containing borehole 900
in
cross section (FIG. 9A) and in cross-sectional view (FIG. 9B). Borehole 900
could be
a borehole resulting from overbalanced drilling into a formation 901, for
example.
Formation 901 is porous, so drilling mud will tend to penetrate into the
formation
from the wellbore. The drilling mud is a slurry that comprises solid
components
suspended in a liquid. As the drilling mud penetrates into the formation, the
solid
components (referred to as filter cake) 902 penetrate a distance r1, whereas
the liquid
components (referred to as filtrate) 903 penetrate further, a distance r2. The
zone of
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the formation that is penetrated by filter cake and/or by filtrate is referred
to as the
invaded zone (it is "invaded" by filter cake and filtrate). Native mobile
fluids present
within the invaded zone are forced out of the invaded zone and into the
surrounding
formation and are replaced by the invading filter cake and filtrate.
[0073] The invaded zone is a potential barrier that can prevent hydrocarbons
from diffusing
from the formation into the wellbore. That barrier may extend a few feet into
the
formation. As mentioned above, explosive perforating guns generate
perforations
through the casing, the cemented annulus, and perhaps several inches to
several feet
into the formation, but do not extend into the formation past the invaded
zone. As a
result, when the wellbore is pressurized with high pressure fracturing fluid,
the force
on the formation is concentrated within the invasion zone and not within the
virgin
formation, where the hydrocarbons are located.
[0074] In contrast to the perforations used during traditional hydraulic
fracturing, the jet
drilled lateral bores of the presently disclosed method extend past the
invaded zone
and into the virgin formation. When those lateral bores are subjected to an
intense
pulse of compressed gas, the power of that impulse impacts the virgin
formation,
where the hydrocarbons are located. Moreover, the lateral bores provide routes
for
the high pressure gas to invade the micro-fissures located in the virgin
formation (e.g.,
outside of r?) and a pathway for the hydrocarbons to reach the wellbore,
bypassing the
barrier created by the invaded zone.
[0075] Another drawback to traditional hydraulic fracturing is that the
fracturing damages the
formation in the region of the created fractures by forcing matter, known as
fines, into
the formation and clogging the porosity of the formation in the vicinity of
those
fractures. Examples of matter that can be forced into the formation include
crushed
grains of rock, crushed proppants, drilling mud and fluid and the like. The
region of
damage around the fractures created during hydraulic fracturing is referred to
as
"fracture face skin" (FFS).
[0076] FIG. 10 illustrates a fracture 1000, as is created during traditional
hydraulic fracturing
of a formation 1001. The formation is subjected to tremendous hydraulic
pressure
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during the fracturing stage. That pressure can compress the formation and
close the
micro-fissures of the formation thereby destroying the gas producing mechanism
of
the gas bearing shale formation. Also, the hydraulic fracturing fluid
typically includes
a proppant material 1002, a portion of which can be pulverized under the
immense
hydraulic pressure. The proppant material is typically a ceramic material or
frac-sand
and is included in the frac fluid to "prop" the facture open. The hydraulic
pressure
forces the fines, pulverized proppant, and other unconsolidated small
particles into the
formation, creating the FFS 1003. The FFS reduces the permeability of the
formation
at the fracture face and can substantially hinder inflow from the formation.
[0077] Unlike traditional hydraulic fracturing, the well stimulation process
described herein
does not deluge the formation with massive amounts of water, gels or other
concoctions. Instead, the fluid contained within the lateral bore 600 (FIG. 6)
is at
essentially hydrostatic pressure. Creating an impulse within the lateral bore
by
releasing high-pressure gas is akin to striking the formation with a hammer.
The
impulse causes the micro-fissures to propagate within the formation, thus
enhancing
the gas producing mechanism of the shale formation but does not compact the
formation or force a substantial amount of liquid or materials into the
formation.
Continuing the analogy, traditional hydraulic fracturing is more akin to
crushing the
fracture face under a steamroller.
[0078] An alternative method of generating an energetic impulse within the
lateral bore is to
remove the in situ formation enhancement tool and replace it with a dedicated
impulse-generating tool, as illustrated in FIG. 11. The impulse-generating
tool 1100
is positioned within a wellbore 1101 having a lateral bore 1102. The impulse-
generating tool can be properly positioned within the wellbore using the same
positioning tool 1103 that was used to position the in situ formation
stimulation tool.
[0079] The impulse-generating tool 1100 can be simply a ported sub having
ports 1104. The
sub may be configured to contain a gas-generating fuel similar to that used to
power
the in situ formation enhancement tool 300. When sufficient gas pressure has
built up
within the impulse-generating tool, the gas is released, causing an impulse.
The
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impulse causes the micro-fissures to propagate within the formation, thus
enhancing
the gas producing mechanism of the shale formation, as described above.
[0080] The impulse-generating tool is a chamber that is fed by a power source
similar to the
power source used in the in situ formation enhancement tool 300. The power
source
can be activated by an electrical impulse on e-line or an electrical impulse
from an
activator run on slickline. The gas power generated by the power source can
enter the
chamber and increase in pressure until the point where a rupture disk or valve
system
is overpowered to the point of opening. Once this point is achieved, the high-
pressure
gas is "dumped" into the formation at a high rate. The impulse causes the
micro-
fissures in the formation to propagate within the formation, thus enhancing
the gas
producing mechanism of the shale formation and gas production is enhanced.
This all
occurs without damage to the formation or alteration of the formations ability
to
produce.
[0081] FIG. 12 schematically illustrates a section of the in situ formation
enhancement tool
300 wherein the piston 308 is within the tool body 304. It can be understood
or
assumed that the section of hose 1201, which is within the diverter sub 312,
will be all
of the hose that will penetrate into the formation when the lateral bore is
jet drilled.
For example, the section of hose 1201 may be about two meters long and may
ultimately penetrate two meters into the formation; boring a two-meter lateral
bore.
Jet drilling two meters through the formation requires a certain volume of
fluid; that
volume must be contained within the tool body 304. To accommodate an adequate
volume of fluid, the tool body 304 may be longer than the diverter sub 312.
For
example, the tool body may be about 4 to 8 meters long and the diverter sub
may be
about 2 to 3 meters long.
[0082] If the tool body 304 is twice as long as the diverter sub 312, then the
hose 1202 within
the tool body must also be twice as long as the hose 120 lwithin the diverter
sub.
When the piston 308 strokes, it will push twice as much hose as will penetrate
into the
formation.
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[0083] FIGS. 13A and 13B illustrates an apparatus 1300 configured with a
telescoping series
of tubes 1220 before (FIG. 13A) and after (FIG. 13B) the piston 308 strokes.
The
telescoping series of tubes allows a longer tool body 304 (and, consequently a
greater
volume of fluid) to be used to drill a lateral bore. As the piston 308
strokes, the
telescoping series of tubes 1220 collapses, as shown in FIG. 13B. The portion
1301
of the hose that extends from the diverter sub 312 into the formation can
therefore be
much shorter than the length of the telescoping series of tubes 1220 that is
pushed by
the piston within the tool body. Therefore, adequate fluid can be supplied to
achieve
the drilling.
[0084] As explained above, the piston 308 serves the dual purpose of (1)
pressurizing the
fluid within the tool body 304 to perform the jet drilling and (2) pushing the
hose into
the formation during drilling. The rate that the piston strokes within the
tool body is
primarily determined by the pressure generated by the gas-producing fuel and
the
resistive pressure of the fluid within the tool body. The rate that the hose
extends into
the formation is primarily determined by the rate at which the piston strokes
(because
the piston pushes the hose into the formation). But that assumes that the rate
of jet
drilling is fast enough to keep up with the rate that hose extends into the
formation.
Depending on the drilling rate, it may be necessary to slow the stroking of
the piston
and thereby slow the extension of the hose into the formation. The power
source
output can be controlled by specifically controlling the rate of burn of the
power
source or by throttling the gas flow from the power source chamber through a
control
valve and into the fluid chamber 304a. The piston can be throttled or slowed
by
attaching geared shafts / mechanisms to the piston that create a positive
force resisting
the downward movement of the piston. The nozzle exits can be sized to restrict
the
flow volume through the nozzle 314, thus increasing the back-pressure created
in the
chamber with the result of slowing the piston travel. The fluid viscosity can
also be
increased, thereby slowing the piston travel.
[0085] FIGS. 14A and B illustrated one embodiment for governing the piston
stroke rate. As
in the previously illustrated embodiments, the piston 308 strokes within the
tool body
304 and collapses the telescoping series of tubes 1220. Note that the tube
1220 may
be a telescoping series of tubes, as illustrated in FIG. 13, but can be drawn
as a simple
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hose 1202 in FIG. 14A for clarity's sake. The piston 308 is modified to
contain a
bearing assembly 1401 that includes linear bearing housings 1402, which are
shown
in more detail in FIG. 14B. The linear bearing housings can ride upon
stationary
threaded shafts 1403. The linear bearing housings 1402 contain bearings 1404,
which
ride within the threads of the shaft 1403, and which translate a portion of
the linear
motion of the piston into radial motion of the bearings, thereby slowing the
piston
stroke speed.
[0086] According to some embodiments, the composition of the fluid within the
fluid
chamber 304a may vary along the length of the chamber. Referring to FIG. 15,
the
composition of fluids A, B and C, contained within the in situ formation
enhancement
tool 300, may differ. Therefore, as the piston 308 strokes, the composition of
the
fluid provided for jet drilling can vary. As the piston 308 strokes, fluid
composition
A will be the first fluid forced through hose 310 and provided for jet-
drilling. If the
well bore is cemented using acid-soluble cement, fluid A may contain an acid,
for
example. Fluid composition B may contain an abrasive component to facilitate
jet
drilling through the formation. Fluid composition C may contain a proppant
material.
[0087] Variation in fluid composition can be maintained by separating the
different fluid
compositions using a barrier material, such as a plastic membrane. For
example, the
different fluids can be contained within bags, which can be loaded into the
fluid
chamber 304a. Alternatively, fluid compositions that are immiscible or that
have
substantially different densities or viscosities may remain separate when
those fluids
are simply loaded into the fluid chamber 304a and not allowed to mix.
[0088] As described above, high-pressure gas contained within the fluid
chamber 304a can
be vented into the lateral bore to provide a stimulating impulse once the
piston 308
completes its stroke. The jet-drilling nozzle 314 may choke the release of the
gas,
diminishing intensity of the impulse. It can therefore be beneficial to remove
the jet-
drilling nozzle prior to generating the impulse. One way of doing that is to
include a
solid material in the fluid capable of knocking the nozzle off the hose once
drilling is
completed. For example, referring to FIG. 15, fluid composition C may contain
metallic shot that can knock the nozzle off of the hose 310, or that can
otherwise
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compromise the structure of the nozzle. Alternatively (or in addition), the
fluid
composition C may include an acid that is capable of dissolving the nozzle.
[0089] FIG. 16 illustrates an embodiment of an apparatus 1600, wherein the
piston 308 is
driven by an electric motor 1601. The electric motor 1601 can be powered
downhole
(for example, with a battery) or can be powered from the surface using an
electric
line. The electric motor 1601 can turn a drive screw 1602, which causes the
piston
308 to stroke. The piston 308 is equipped with drive bearings 1603.
[0090] As used herein, the term in situ formation enhancement tool generally
refers to an
apparatus comprising one or more of and in situ pump for providing high
pressure
fluid, a jet-drilling apparatus for drilling a lateral bore, and a high
pressure gas source
for releasing a pulse of high pressure gas. The foregoing disclosure and the
showings
made of the drawings are merely illustrative of the principles of this
invention and are
not to be interpreted in a limiting sense.
