U.S. patent application number 10/958434 was filed with the patent office on 2006-04-06 for system and method for fracturing a hydrocarbon producing formation.
Invention is credited to Donald M. Justus, Billy W. McDaniel, Jim B. Surjaatmadja.
Application Number | 20060070740 10/958434 |
Document ID | / |
Family ID | 36124390 |
Filed Date | 2006-04-06 |
United States Patent
Application |
20060070740 |
Kind Code |
A1 |
Surjaatmadja; Jim B. ; et
al. |
April 6, 2006 |
System and method for fracturing a hydrocarbon producing
formation
Abstract
A system and method for fracturing a hydrocarbon producing
formation in which a fracturing tool is inserted in a wellbore
adjacent the formation, and fracturing fluid is introduced into the
annulus between the fracturing tool and the wellbore and flows to
the formation.
Inventors: |
Surjaatmadja; Jim B.;
(Duncan, OK) ; McDaniel; Billy W.; (Duncan,
OK) ; Justus; Donald M.; (Houston, TX) |
Correspondence
Address: |
JOHN W. WUSTENBERG
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Family ID: |
36124390 |
Appl. No.: |
10/958434 |
Filed: |
October 5, 2004 |
Current U.S.
Class: |
166/308.1 ;
166/177.5 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/114 20130101 |
Class at
Publication: |
166/308.1 ;
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 28/00 20060101 E21B028/00 |
Claims
1. A method of fracturing a subterranean formation penetrated by a
wellbore, comprising the steps of: (a) positioning a fracturing
tool within the wellbore, wherein the fracturing tool has a
fracturing tool outer wall; (b) initiating a fracture having a
center of fracture point, wherein the center of fracture point is
located within the subterranean formation but not within the
wellbore; and (c) creating the fracture.
2. The method of claim 1 wherein the wellbore comprises a
substantially vertical section, and step (a) further comprises the
step of positioning the fracturing tool within the substantially
vertical portion of the wellbore.
3. The method of claim 1 wherein the wellbore comprises a
substantially horizontal section, and step (a) further comprises
the step of positioning the fracturing tool within the
substantially horizontal portion of the wellbore.
4. The method of claim 1 wherein the fracturing tool comprises
nozzles.
5. The method of claim 4 wherein the nozzles are angled at an acute
angle to the fracturing tool outer wall.
6. The method of claim 5 wherein the center of fracture point is at
an acute angle to the fracturing tool outer wall.
7. The method of claim 1 wherein: the fracturing tool comprises a
hydrajetting tool assembly mechanically connected to a work string;
the work string comprises an outer wall and an inner wall; and the
hydrajetting tool assembly comprises: a hydrajetting sub defined by
an outer wall and an inner fluid flow passageway; a port formed
through the outer wall of the hydrajetting sub and adapted to
communicate with the inner fluid flow passageway; a nozzle mounted
within the port; and a directional sub, wherein the directional sub
is mechanically connected to the hydrajetting sub.
8. A method of fracturing a subterranean formation penetrated by a
wellbore, comprising the steps of: (a) positioning a hydrajetting
tool assembly within the wellbore, wherein the hydrajetting tool
assembly comprises: a hydrajetting sub defined by an outer wall and
an inner fluid flow passageway; a port formed through the outer
wall and adapted to communicate with the inner fluid flow
passageway; a nozzle mounted within the port; and a directional
sub, wherein the directional sub is mechanically connected to the
hydrajetting sub; (b) initiating a fracture having a center of
fracture point by introducing a fracturing fluid into the inner
fluid flow passageway of the hydrajetting sub and jetting the
fracturing fluid through the nozzle against the subterranean
formation at a pressure sufficient to form cavities in the
formation, wherein the center of fracture point is located within
the subterranean formation but not within the wellbore, and the
cavities in the subterranean formation are in fluid communication
with the wellbore; and (c) creating the facture by maintaining the
fracturing fluid in the cavities while jetting at a sufficient
static pressure to fracture the subterranean formation.
9. The method of claim 8 further comprising prior to step (b) the
steps of: establishing a desired orientation of the hydrajetting
tool assembly; determining the orientation of the hydrajetting tool
assembly with the directional sub; and rotating the hydrajetting
tool so that the orientation of hydrajetting tool assembly equals
the desired orientation of the hydrajetting tool assembly.
10. The method of claim 8 wherein the hydrajetting tool assembly
further comprises a packer, and the method further comprises the
step of forming a seal to prevent fluid flow downstream of the seal
and to permit the flow of the fracturing fluid into the
subterranean formation.
11. The method of claim 10 wherein the step of forming the seal
comprises the steps of: connecting the packer to the hydrajetting
tool assembly; and setting the packer.
12. The method of claim 8 further comprising the steps of: adding a
propping agent to the fracturing fluid; and propelling the propping
agent into the cavities.
13. The method of claim 8 further comprising the step of adding a
consolidation agent to the fracturing fluid.
14. The method of claim 8 wherein the consolidation agent is a
resin coated proppant.
15. The method of claim 8 further comprising following step (c) the
step of packing the wellbore by introducing a fluid slurry into
wellbore.
16. The method of claim 15 wherein the fluid slurry comprises
gravel.
17. A hydrajetting tool assembly comprising: a hydrajetting sub
defined by an outer wall and an inner fluid flow passageway; a port
formed through the outer wall and adapted to communicate with the
inner fluid flow passageway; a nozzle mounted within the port; and
a directional tool, wherein the directional tool is mechanically
connected to the hydrajetting sub.
18. The hydrajetting tool assembly of claim 17 wherein the nozzle
is comprised of tungsten carbide or ceramic.
19. The hydrajetting tool assembly of claim 17 wherein the nozzle
extends beyond the outer wall and is oriented at an angle between
about 30 degrees and about 90 degrees relative to the outer
wall.
20. The hydrajetting tool assembly of claim 19 wherein the nozzle
is oriented at an angle between about 45 degrees and about 90
degrees relative to the outer wall.
21. The hydrajetting tool assembly of claim 17 wherein the port is
approximately circular.
22. The hydrajetting tool assembly of claim 17 wherein: the
hydrajetting tool assembly is mechanically connected to a work
string; the work string comprises: an outer wall; an inner wall; a
non-conducting material; and a conducting material between the work
string outer wall and the work string inner wall; and the
hydrajetting tool assembly is capable of communicating with surface
equipment through the conducting material
23. The hydrajetting tool assembly of claim 17 further comprising a
mud pulse or sonic generator connected to the hydrajetting sub.
24. The hydrajetting tool assembly of claim 17 further comprising a
plurality of ports and a plurality of nozzles, wherein the nozzles
are mounted within the ports.
25. The hydrajetting tool assembly of claim 24 wherein the nozzles
are oriented in an approximately unitary direction.
26. The hydrajetting tool assembly of claim 24 wherein the nozzles
are located in two rows arranged longitudinally along the
hydrajetting sub, and the rows are located 180.degree. apart.
27. The hydrajetting tool assembly of claim 17 further comprising a
downhole power unit mechanically connected to the hydrajetting
sub.
28. The hydrajetting tool assembly of claim 27 wherein the downhole
power unit comprises a battery, fuel cell, or fluid motor and
generator.
29. The hydrajetting tool assembly of claim 17 further comprising a
rotating sleeve mechanically connected to the hydrajetting sub.
30. The hydrajetting tool assembly of claim 29 further comprising a
downhole power unit mechanically connected to the rotating
sleeve.
31. The hydrajetting tool assembly of claim 30 wherein the
hydrajetting sub is directly connected to rotating sleeve, and the
rotating sleeve is directly connected to the downhole power
unit.
32. The hydrajetting tool assembly of claim 17 further comprising a
check valve mechanically connected to the hydrajetting sub.
33. The hydrajetting tool assembly of claim 32 further comprising a
temperature sensor.
34. The hydrajetting tool assembly of claim 32 further comprising a
pressure sensor.
35. The hydrajetting tool assembly of claim 17 further comprising a
packing device mechanically connected to the hydrajetting sub,
wherein the packing device is capable of seating against the
wellbore to form a seal.
36. The hydrajetting tool assembly of claim 17 wherein the
directional tool comprises a gyroscopic surveyor, a wireline
steerer, a memory pulsed neutron logging device, or an
electromagnetic logging device.
37. The hydrajetting tool assembly of claim 36 wherein the
directional tool is capable of communicating with surface
equipment.
38. The hydrajetting tool assembly of claim 36 wherein the
directional tool further comprises an integrated power system.
39. The hydrajetting tool assembly of claim 17 further comprising a
hole finder mechanically connected to the hydrajetting tool.
40. The hydrajetting tool assembly of claim 17 further comprising a
gamma radiation source mechanically connected to the hydrajetting
sub.
41. The hydrajetting tool assembly of claim 17 further comprising a
collar locator mechanically connected to the hydrajetting sub.
Description
BACKGROUND
[0001] This invention relates to a system and method for fracturing
a hydrocarbon-producing formation with a fracturing system located
in a wellbore adjacent the formation.
[0002] Hydraulic fracturing is often utilized to stimulate the
production of hydrocarbons from subterranean formations penetrated
by wellbores. Such hydraulic fracturing treatments typically
include perforating the well casing adjacent the formation and
introducing a fracturing fluid through tubing into a tool assembly
in the casing, and to a ported sub, or the like, connected in the
tool assembly. The fluid discharges from the ported sub at a
relatively high pressure and passes through the perforations in the
well casing and into the formation to fracture it and promote the
production of the hydrocarbons such as oil and/or gas. Where only
one portion of a formation is to be fractured as a separate stage,
it is isolated from the other perforated portions of the formation
using conventional packers or the like, and a fracturing fluid is
pumped into the wellbore through the perforations in the well
casing and into the isolated portion of the formation to be
stimulated at a rate and pressure such that fractures are formed
and extended in the formation. Propping agent may be suspended in
the fracturing fluid which is deposited in the fractures. The
propping agent functions to prevent the fractures from closing,
thereby providing conductive channels in the formation through
which produced fluids can readily flow to the wellbore. In certain
formations, this process is repeated in order to thoroughly
populate multiple formation zones or the entire formation with
fractures.
[0003] In situations where casing is not present, it is sometimes
desirable to use the above approach to create a preferential center
of fracture point. In general, this center of fracture point
coincides with the center of the tubing or casing. Such a method is
described in U.S. Pat. No. 5,765,642, where a jetting tool is used
to place such fractures, with or without the use of isolation
methods.
[0004] However, these types of techniques are not without problems.
For example, it is typically not possible with traditional
fracturing technology to direct the fracture in a specific
direction, as fractures are controlled primarily by the mechanics
of the formation and the wellbore. In traditional fracturing
methods, the center of the fracture is in the center of the tubing
or casing. This may result in fracturing into water-producing
formations or fracturing into another known undesirable fracture or
well. Such methods may also result in fracturing in the direction
of least principle stress creating near-wellbore-toruosity during
the fracture treatment and possible formation sand flowback
problems.
[0005] Also, with traditional methods of well fracture it is
typically not possible to determine the exact location and
orientation of the ported sub, and hence, the exact location of the
fractures to be formed. Further, traditional hydraulic fracturing
tools most often lack critical equipment necessary to complete
other procedures in the wellbore, such as packing, orientation and
the like. These traditional hydraulic fracturing tools must most
often be removed from the wellbore and other tools inserted for
such additional procedures, resulting in additional time and costs.
Therefore, what is needed is a fracturing system and method that
eliminates the above problems.
SUMMARY
[0006] The present invention is directed to an apparatus and method
for fracturing and/or perforating a formation.
[0007] More specifically, one embodiment of the present invention
is directed to a method of fracturing a subterranean formation
penetrated by a wellbore by positioning a fracturing tool within
the wellbore, with the fracturing tool having a fracturing tool
outer wall. A fracture is initiated with the center of fracture
point located within the subterranean formation but not within the
wellbore. A fracture is then created.
[0008] Another embodiment of the present invention is directed to a
method of fracturing a subterranean formation penetrated by a
wellbore by positioning a hydrajetting tool assembly within the
wellbore. The hydrajetting tool assembly has a hydrajetting sub
capable of being inserted into a wellbore. The hydrajetting tool
assembly includes a hydrajetting sub defined by an outer wall and
an inner fluid flow passageway, and a port formed through the outer
wall and adapted to communicate with the inner fluid flow
passageway, a nozzle mounted within the port, and a directional
sub, wherein the directional sub is mechanically connected to the
hydrajetting sub. A fracture is initiated, wherein the center of
fracture point is located within the subterranean formation but not
within the wellbore by introducing a fracturing fluid into the
inner fluid flow passageway of the hydrajetting sub and jetting the
fracturing fluid through the nozzle against the subterranean
formation at a pressure sufficient to form cavities in the
formation, wherein the cavities in the formation are in fluid
communication with the wellbore. A fracture is created by
maintaining the fracturing fluid in the cavities while jetting at a
sufficient static pressure to fracture the subterranean
formation.
[0009] Still another embodiment of the present invention is
directed to a hydrajetting tool assembly mechanically connected to
a work string, wherein the work string comprises an outer wall and
an inner wall. The hydrajetting tool assembly is capable of being
inserted into a wellbore and includes a hydrajetting sub defined by
hydrajetting sub outer wall, an inner fluid flow passageway, and a
port formed through the outer wall adopted to communicate with the
inner fluid flow passageway. The hydrajetting tool assembly further
includes a nozzle mounted within the port and a directional tool
mechanically connected to the hydrajetting sub.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] A more complete understanding of the present disclosure and
advantages thereof may be acquired by referring to the following
description taken in conjunction with the accompanying
drawings:
[0011] FIG. 1 is an overview of subterranean formation fractured
using a traditional fracturing tool in a mostly vertical section of
a wellbore.
[0012] FIG. 1a is an overview of a subterranean formation fractured
using a fracturing tool of the present invention in a mostly
vertical section of a wellbore.
[0013] FIG. 1b is an overview of a subterranean formation fractured
using a fracturing tool of the present invention in a mostly
horizontal section of a wellbore.
[0014] FIG. 1c is an overview of a subterranean formation fractured
using a fracturing tool of the present invention in a mostly
vertical section of a wellbore
[0015] FIG. 2 is an elevational view of one embodiment of a
hydrajetting tool assembly according to the present invention.
[0016] FIG. 3 is a cutaway view of an embodiment of a hydrajetting
tool assembly according to the present invention.
[0017] FIG. 4 is a cutaway view of one embodiment of a check valve
included in one embodiment of the hydrajetting tool assembly
according to the present invention.
[0018] FIG. 5 is a schematic diagram of a subterranean formation
depicting use of one embodiment of a hydrajetting tool assembly
according to the present invention.
[0019] FIG. 6 is a schematic diagram of a subterranean formation
fractured using one embodiment of a hydrajetting tool assembly
according to the present invention
DETAILED DESCRIPTION
[0020] As described above, it is typically not possible with
traditional fracturing technology to direct the fracture in a
specific direction. Further, traditional fracturing methods
typically have a center of fracture point in the center of the
tubing or casing. FIG. 1 depicts one embodiment of a traditional
fracturing operation. Traditional fracturing tool 1000 is shown
located within wellbore 1100. Wellbore 1100 is located within
formation 1150. Numerous embodiments of traditional fracturing
tools 1000 exist. Traditional fracturing tool 1000 shown in FIG. 1
has nozzles 1010 located on opposite sides of traditional
fracturing tool 1000. In other embodiments of traditional
fracturing tool 1000, nozzles 1010 may be located in four positions
located 90 degrees apart around the circumference of traditional
fracturing tool 1000; in still other embodiments of traditional
fracturing tool 1000, other configurations of nozzles may be placed
around the circumference of traditional fracturing tool 1000,
including, but not limited to, every 60 degrees or every 30
degrees. In yet still other embodiments of traditional fracturing
tool 1000, nozzles may be replaced with ports or other methods of
transferring fluids in the wellbore. Various embodiments of
traditional fracturing tool 1000 typically have one primary
characteristic in common, i.e., when fluid is introduced through
into and through traditional fracturing tool 1000, such fluid exits
about the circumference of traditional fracturing tool 1000. This
multi-directional exit characteristic common to typical traditional
fracturing tools 1000 forms fracture 1200 in formation 1150. Center
of fracture point 1250 is therefore typically located within
wellbore 1100 when using traditional fracturing tools 1000. In some
embodiments of traditional fracturing tool 1000, a positioner is
used to determine the orientation and/or location of traditional
fracturing tool 1000.
[0021] A fracturing operation in a substantially vertical section
of wellbore 1100 using a fracturing tool of the present invention
is depicted in FIG. 1a. Fracturing tool 2000 is shown having
nozzles 2020 in approximately a unitary direction. While fracturing
tool 2000 is shown having nozzles 2020, any traditional fracturing
tool may be used in the present invention as long as the method of
introducing fluid into wellbore 1100 is limited to approximately a
unitary direction. When fluid is introduced through into and
through fracturing tool 2000, such as through nozzles as shown in
FIG. 1a, the fluid exits fracturing tool 2000 in approximately a
unitary direction. Hence, when formation 1150 is fractured, as
shown in FIG. 1a using one embodiment of the present invention,
fracture 1200 has center of fracture point 1250 located away from
wellbore 1100, i.e., not located within wellbore 1100.
[0022] FIG. 1a further depicts directional tool 2100. Directional
tool 2100 is mechanically connected to fracturing tool 2000.
Directional tool 2100 may be any one of a number of devices
suitable for determining both the inclination and azimuth angle of
fracturing tool 2000. Suitable examples of directional tool 2100
include, but are not limited to, gyroscopic surveyors, wireline
steerers, memory pulsed neutron logging devices, and
electromagnetic logging devices. Note that directional tool 2100
may include those types of tools described below as types of
directional sub 40. Through the use of the combination of
directional tool 2100, the operator may determine the inclination
and azimuth angle of fracturing tool 2000. The operator may then
rotate fracturing tool 2000 to the appropriate predetermined
position, either through the use of surface equipment or downhole
equipment. Thus, the operator may, through the use of the
combination of fracturing tool 2000 and directional tool 2100 to
create center of fracture point 1250 at any location about wellbore
1100 as desired. FIG. 1b depicts a substantially identical
operation in a substantially horizontal section of wellbore
1100.
[0023] By orienting nozzles at an angle from fracturing tool wall
2030, as shown in FIG. 1c, it is possible to orient the fracture at
an angle from the wellbore. For instance, when in a mostly vertical
section of the wellbore, in the embodiment shown in FIG. 1c,
nozzles 22 are at an acute angle to fracturing tool wall 2030. As
further shown in FIG. 1c, by orienting nozzles 22 at an acute angle
to the fracturing tool wall 2030, center of fracture point 1250 is
placed at an acute angle to the wellbore and the later-resultant
fractures will propagate, at least in part, at an acute angle to
the wellbore.
[0024] Referring now to FIG. 2, a fracturing tool for use in
accordance with one embodiment of the present invention, a
hydrajetting tool assembly, is illustrated and generally designated
by the numeral 10. In discussion of the hydrajetting tool assembly
10, the terms "above" and "below" are used to denote positions of
equipment associated with hydrajetting tool assembly 10. Such
references are to positions of equipment in a vertical section of
the wellbore, but are used only to denote position, not to limit
hydrajetting tool assembly 10 to any particular wellbore section.
The hydrajetting tool assembly 10 is shown connected to a work
string 12 through which a fluid may be pumped at a high pressure.
Work string 12 is typically jointed pipe or coiled tubing. In one
embodiment of the present invention, work string 12 is capable of
transmitting data to and from the surface via wireline
communication, typically from hydrajetting tool assembly 10 to
surface equipment. Where wireline communication is used, conducting
material is installed between the outer and inner walls of work
string 12. Typically, when utilizing conducting material, work
string 12 should be composed of a composite material with limited
ability to conduct electricity to avoid electrical shorts. The
conducting material connects surface equipment with hydrajetting
tool assembly 10, described below, to allow communication between
surface equipment and hydrajetting tool assembly 10. Other
non-limiting means of communication between hydrajetting tool
assembly 10 and surface equipment include mud pulse or sonic
communication means. Where mud pulse or sonic communication is
used, mud pulse or sonic generators are generally affixed to
hydrajetting tool assembly 10 and used to communicate between
hydrajetting tool assembly 10 and surface equipment through
drilling mud and work string 12, respectively.
[0025] Hydrajetting tool assembly 10 is comprised of at least
hydrajetting sub 20 and directional sub 40. Referring to FIG. 3,
hydrajetting sub 20 includes an inner fluid flow passageway 18
extending therethrough and communicating with at least one and
preferably as many as feasible, angularly-spaced, lateral, ports 21
disposed through the sides of hydrajetting sub 20. A nozzle 22 is
mounted within each of ports 21. As will be described further
hereinbelow, nozzles 22 are preferably disposed in a single plane
which is positioned at a predetermined orientation with respect to
the longitudinal axis of hydrajetting sub 20. Such orientation of
the plane of nozzles 22 typically coincides with the orientation of
the plane of minimum principal stress in the formation to be
fractured relative to the longitudinal axis of the wellbore
penetrating the formation.
[0026] Ports 21 are generally approximately circular openings,
although other shapes may be used depending on the particular
design parameters. Ports 21 are designed to allow the mounting of
nozzles 22 within ports 21. Nozzles 22 are designed to allow fluid
flow from inner fluid flow passageway 18 through hydrajetting sub
outer wall 24. Nozzles 22 are further designed to cause fluid
impingement on formation 1150, as shown in FIG. 5. Nozzles 22 may
extend beyond the surface of hydrajetting sub 20, as shown in FIG.
2, or nozzles 22 may terminate at the surface of hydrajetting sub
20. In an exemplary embodiment where nozzles 22 extend beyond the
surface of hydrajetting sub 20, nozzles. 22 are approximately
cylindrical, hollow projections that may be in a straight line
orientation, but may more commonly be oriented at an angle between
about 1.degree. and about 90.degree. from hydrajetting sub outer
wall 24, often between about 30.degree. and about 90.degree., with
some embodiments between about 40.degree. and about 90.degree..
Nozzles 22 orientation and location are dependent upon the
formation to be fractured. Nozzle 22 orientation may coincide with
the orientation of the plane of minimum principal stress, or the
plane perpendicular to the minimum stress direction in the
formation to be fractured relative to the axial orientation of
wellbore 1100 penetrating the formation. Nozzle 22 circumferential
location about hydrajetting sub 20 should be chosen depending on
the particular well, field or, formation to be fractured. For
instance, in certain circumstances, it may be desirable to orient
all nozzles 22 in one direction or at 180.degree. stations about
the circumference of hydrajetting sub 20 for other formations. As
described above, when it is desirable to form a fracture initiation
point outside the wellbore, nozzles 22 should be oriented in
approximately a unitary direction. It is further possible to alter
the internal diameter of nozzles 22 dependent upon operator need.
One of ordinary skill in the art may vary these parameters to
achieve the most effective treatment for the particular well.
[0027] In typical embodiments, nozzles 22 have a diameter sized so
as to increase the pressure of the fluid being jetted through
nozzles 22 to a suitable pressure to cause microfractures in
formation 1150 or to perforate any wellbore casing that may be
present. The increased pressure allowed by reducing the diameter of
nozzles 22 increases the pressure drop of fluid traveling through
nozzles 22. Nozzles 22 may be composed of any material that is
capable of withstanding the stresses associated with fluid fracture
of formation 1150 and the abrasive nature of the fracturing or
other treatment fluid and any proppants or other fracturing agents
used. Nonlimiting examples of an appropriate material of
construction of nozzles 22 are tungsten carbide and certain
ceramics.
[0028] Mechanically connected to hydrajetting sub 20 in one
embodiment of the present invention is downhole power unit (DPU)
14. DPU 14 is a self-contained unit designed to provide electrical
power to downhole equipment, such as the equipment described below.
DPU 14 is most commonly a device containing a battery, a fuel cell
or a fluid motor/generator combination. An acceptable device for
use as DPU 14 is the Downhole Power Unit available from Halliburton
Energy Services, Inc. In at least one embodiment of the present
invention, DPU 14 is electrically connected to work string 12 so as
to allow data transmission to DPU 14 through the conducting
materials within the walls of work string 12. DPU 14 may be located
above hydrajetting sub 20, as shown in FIG. 2 or below hydrajetting
sub 20. Where DPU 14 is located above hydrajetting sub 20, it must
be designed so as to allow fluid flow to inner fluid flow
passageway 18. Where DPU 14 is located below hydrajetting sub 20,
it may be designed to allow fluid flow to pass through it, or DPU
14 may also act as a plug such that no treatment fluids, for
instance, the fracturing fluid, may exit through the open end of
hydrajetting tool assembly 10. In another embodiment of the present
invention, DPU 14 is absent and rotation may be provided from
surface equipment, such as through conductive material located
within the wall of work string 12.
[0029] Hydrajetting sub 20 is typically mechanically connected,
either directly, as shown in FIG. 2, or indirectly, to rotating
sleeve 16. Rotating sleeve 16 is designed to be rotated about its
longitudinal axis and, by the connection between hydrajetting sub
20 and rotating sleeve 16, rotate hydrajetting sub 20 about its
longitudinal axis. Hence, by changing the orientation of rotating
sleeve 16 about its longitudinal axis, nozzles 22 may be rotated
about the longitudinal axis of the wellbore. Rotation of rotating
sleeve 16 may be achieved by a mechanical connection to DPU 14, or
by surface equipment. In another embodiment of the present
invention, rotating sleeve 16 may be omitted and hydrajetting sub
20 may be oriented by means of surface equipment.
[0030] In particular embodiments of the present invention,
hydrajetting sub 20 may be mechanically connected to check valve
200. Check valve 200, as shown in FIG. 4, is in some embodiments of
the present invention, a tubular, ball activated, check valve that
is connected to the end of the hydrajetting sub 20 opposite from
the work string 12. Check valve 200 includes a longitudinal flow
passageway 202 extending therethrough, which in the embodiment
shown in FIG. 4, connects with inner fluid flow passageway 18.
Longitudinal passageway 202 typically includes reduced diameter
longitudinal bore 204 through the exterior end portion of the check
valve 200 and a larger diameter counter bore 206 through the
forward portion of check valve 200 which forms an annular seating
surface 208 in the valve member for receiving a ball 210. As will
be understood by those skilled in the art, prior to when ball 210
is dropped into check valve 200 as shown in FIG. 4, fluid freely
flows through hydrajetting sub 20 and check valve 200. After ball
210 is seated on annular seating surface 208 in check valve 200 as
illustrated in FIG. 4, flow through check valve 200 is terminated,
causing fluid passing into work string 12 and hydrajetting sub 20
to exit hydrajetting sub 20 via nozzles 22. When it is desired to
reverse circulate fluids through check valve 200, hydrajetting sub
20 and work string 12, the fluid pressure exerted within work
string 12 is reduced whereby higher pressure fluid surrounding
hydrajetting sub 20 and check valve 200 flows through check valve
200, causing ball 210 to be pushed out of engagement with the
annular seating surface 208, and through nozzles 22 into and
through work string 12. As will be appreciated by one of ordinary
skill in the art, check valve 200 is only one of a number of
possible permutations of possible check valves for use in the
present invention and the present invention is not limited to only
the presently described check valve 200. Further, it is possible to
replace check valves such as check valve 200 with a plug. In
addition, as described above, in certain embodiments of the present
invention where DPU 14 is located below hydrajetting sub 20, DPU 14
may act to prevent liquid from exiting inner fluid flow passageway
18 except through nozzles 22. In embodiments containing a plug in
place of check valve 200, or when DPU 14 acts to prevent liquid
from exiting inner fluid flow passageway's except through nozzles
22, all fluid entering work string 12 exits through nozzles 22. An
optional pressure and/or temperature sensor, may be used to
determine the pressure and temperature characteristics of the fluid
exiting through check valve 200, such as through reduced diameter
longitudinal bore 204.
[0031] Hydrajetting tool assembly 10 may in certain embodiments
include packing device 300. Packing device 300 is any one of a
number of packers known to those of skill in the art for sealing
the wellbore. This seal is designed to isolate the portion of the
formation to be fractured from portions below or beyond
hydrajetting tool assembly 10. It is not expected that the seal
formed by packing device 300 be complete, but it should be
sufficient to allow fracturing of the desired formation. Typically,
packing device 300 will seat against the sides of the wellbore or
well casing to form this seal. Packing device 300 is typically
located below hydrajetting sub 20.
[0032] Hydrajetting tool assembly 10 further includes directional
sub 40. Directional sub 40 may include any number of devices
suitable for determining both the inclination and azimuth angle of
hydrajetting tool assembly 10. Suitable examples of directional sub
40 include, but are not limited to, gyroscopic surveyors, wireline
steerers, memory pulsed neutron logging devices, and
electromagnetic logging devices, all of which are familiar to those
of ordinary skill in the art. Directional sub 40 is designed to
communicate with surface equipment through such communications
means as mud pulse, sonic, and wireline. Directional sub 40 may be
powered by DPU 14 or, in the alternative, may be powered by an
integrated power system, typically a device containing batteries.
Alternatively, for instance, in embodiments where DPU 14 is absent,
directional sub 40 may be powered from the surface through
conducting material located within the wall of work string 12.
Directional sub 40 is mechanically connected to hydrajetting sub
20. In some embodiments of the present invention, directional sub
40 is located such that other equipment, for example packing device
300, is mechanically located between directional sub 40 and
hydrajetting sub 20. Such positioning may be desirable to lessen
vibrational effects of hydrajetting sub 20 on sensitive electronic
or mechanical components of directional sub 40.
[0033] Additional equipment that may be included in hydrajetting
tool assembly 10 includes a hole finder, i.e., a device commonly
used in drilling to find holes in piping such as liners or casing,
gamma radiation source, a device used to determine, and a collar
locator, i.e., a device designed to detect drill pipe collars.
Typically, this additional equipment will be located contiguous
with directional sub 40, although any appropriate location on
hydrajetting tool assembly 10 may be used for such equipment.
[0034] Referring now to FIG. 5, a hydrocarbon producing formation
1150 is illustrated penetrated by wellbore 1100. Wellbore 1100
includes substantially vertical portion 404 which extends to the
surface, and may include substantially horizontal portion 406 which
extends into formation 1150. Work string 12 having the hydrajetting
tool assembly 10 and an optional centralizer 408, a device designed
to maintain hydrajetting tool assembly 10 at least some distance
away from the sides of wellbore 1100 and preferably at or near the
center of wellbore 1100, attached thereto is shown disposed in
wellbore 1100. In certain situations, substantially horizontal
portion 406 of wellbore 1100 may be lined with wellbore casing 410.
Wellbore casing 410 may be used to stabilize wellbore 1100, prevent
communication between different sections of formation 1150, and/or
prevent seepage of hydrocarbon fluids into wellbore 1100 prior to a
desired time.
[0035] Hydrajetting tool assembly 10 is positioned in wellbore 1100
adjacent to the portion of formation 1150 to be fractured. Packing
device 300 is then set so that if forms a seal as described above
in wellbore 1100. In one embodiment of the present invention
wherein check valve 200 is used, a fluid is pumped through work
string 12 and through hydrajetting tool assembly 10, whereby the
fluid flows through the check valve 200 and circulates through
wellbore 1100. The circulation is preferably continued for a period
of time sufficient to clean debris, pipe dope and other materials
from inside work string 12 and from wellbore 1100. Thereafter, ball
210 is dropped through work string 12, through hydrajetting sub 20
and into check valve 200 while continuously pumping fluid through
work string 12 and hydrajetting tool assembly 10. When ball 210
seats on annular seating surface 208 in check valve 200, fluid is
forced through nozzle 22 of hydrajetting sub 20. The rate of
pumping the fluid into the work string 12 and through the
hydrajetting sub 20 is increased to a level whereby the pressure of
the fluid which is jetted through the nozzles 22 reaches a desired
jetting pressure.
[0036] In sections of open hole wellbore 1100 having wellbore
casing 410, it may be necessary to perforate wellbore casing 410
before forming microfractures, such as through the use of
hydrajetting sub 20. Hydrajetting sub 20 may be used to make a
number of different types of perforations in wellbore casing 410,
commonly described as "cuts." For instance, in certain formations,
wellbore casing 410 may be perforated in only a single direction,
e.g., towards the surface. In such a case, where nozzles 22 are
oriented in one direction, fluid may be forced through nozzles 22
in that single direction. Generally, in such situations,
directional sub 40 is used to determine the orientation of
hydrajetting sub 20. Hydrajetting sub 20 may then be oriented
through rotation, either by rotating sleeve 16 or from surface
equipment, so that nozzles 22 point in the desired direction. Fluid
may then be forced through nozzles 22 to make the single direction
cut.
[0037] Where it is desirable to make multiple perforations at
different circumferential locations about wellbore casing 410,
after the initial perforation, fluid flow through nozzles 22 may be
stopped, hydrajetting sub 20 may be rotated, as described above, to
a different circumferential location, and fluid flow through
nozzles 22 restarted. This process may be repeated as necessary to
completely perforate wellbore casing 410. In other situations, it
may be desirable to make a longitudinal cut of wellbore casing 410,
called a "vertical cut" when the longitudinal cut is made in mostly
substantially vertical portion 404. When a longitudinal cut is
desired, hydrajetting tool assembly 10 is raised or lowered while
fluid is jetted through nozzles 22. In addition, it certain
situations it may be desirable to make a spiral cut of wellbore
casing 410. Normally, a spiral cut is made when it is necessary to
cut the wellbore casing 410 around its entire circumference, for
instance, when the well is to be abandoned. In such a situation,
fluid is jetted through nozzles 22 while hydrajetting sub 20 is
rotated, either by use of rotating sleeve 16 or through the use of
surface equipment.
[0038] Further, fluid jetted through nozzles 22 may be used to
cause the creation of the cavities 50 and microfractures 52 in
formation 1150 as illustrated in FIG. 6. FIG. 6 depicts a situation
wherein the center of fracture point is centered on wellbore 1100.
As described previously, where the center of fracture point is not
centered on wellbore 1100, such fractures would be centered in an
area outside wellbore 1100. Directional sub 40 is used to determine
the orientation of hydrajetting sub 20 within wellbore 1100.
Rotating sleeve 16 or surface equipment may then be used to orient
hydrajetting sub 20 within wellbore 1100. A variety of fluids can
be utilized in accordance with the present invention for forming
fractures, including aqueous fluids, viscosified fluids, oil based
fluids, and even certain "non-damaging" drilling fluids known in
the art. Various additives can also be included in the fluids
utilized such as abrasives, fracture propping agent, e.g., sand or
artificial proppants, acid to dissolve formation materials and
other additives known to those skilled in the art.
[0039] As will be described further hereinbelow, the jet
differential pressure (P.sub.jd) at which the fluid must be jetted
from nozzles 22 to result in the formation of the cavities 50 and
microfractures 52 in the formation 1150 is a pressure of
approximately two times the pressure (P.sub.i) required to initiate
a fracture in the formation less the ambient pressure (P.sub.a) in
the wellbore adjacent to the formation i.e.,
P.sub.jd.gtoreq.2.times.(P.sub.I-P.sub.a). The pressure required to
initiate a fracture in a particular formation is dependent upon the
particular type of rock and/or other materials forming the
formation and other factors known to those skilled in the art.
Generally, after a wellbore is drilled into a formation, the
fracture initiation pressure can be determined based on information
gained during drilling and other known information. Since wellbores
are often filled with drilling fluid and since many drilling fluids
are undesired, the fluid could be circulated out, and replaced with
desirable fluids that are compatible with the formation. The
ambient pressure in the wellbore adjacent to the formation being
fractured is the hydrostatic pressure exerted on the formation by
the fluid in the wellbore or a higher pressure caused by fluid
injection.
[0040] As mentioned above, propping agent may be combined with the
fluid being jetted so that it is carried into the cavities 50 into
fractures 60 connected to the cavities. The propping agent
functions to prop open fractures 60 when they attempt to close as a
result of the termination of the fracturing process. In order to
insure that propping agent remains in the factures when they close,
the jetting pressure is preferably slowly reduced to allow
fractures 60 to close on propping agent which is held in the
fractures by the fluid jetting during the closure process. In
addition to propping the fractures open, the presence of the
propping agent, e.g., sand, serves as an abrasive agent and in the
fluid being jetted facilitates the cutting and erosion of the
formation by the fluid jets. As indicated, additional abrasive
material can be included in the fluid, as can one or more acids
which react with and dissolve formation materials to enlarge the
cavities and fractures as they are formed.
[0041] As further mentioned above, some or all of the
microfractures produced in a subterranean formation can be extended
into the formation by pumping a fluid into the wellbore to raise
the ambient pressure therein. That is, in carrying out the methods
of the present invention to form and extend a fracture in the
present invention, hydrajetting sub 20 is positioned in wellbore
1100 adjacent the portion of formation 1150 to be fractured and
fluid is jetted through the nozzles 22 against the formation 1150
at a jetting pressure sufficient to form the cavities 50 and the
microfractures 52. Simultaneously with the hydrajetting of the
formation, a fluid may be pumped into wellbore 1100 at a rate to
raise the ambient pressure in wellbore 1100 adjacent formation 1150
to a level such that the cavities 50 and microfractures 52 are
enlarged and extended whereby enlarged and extended fractures 60
are formed. As shown in FIG. 6, the enlarged and extended fractures
60 are preferably formed in spaced relationship along wellbore 1100
with groups of the cavities 50 and microfractures 52 formed
therebetween.
[0042] Following the fracture of formation 1150, the annulus or
wellbore may be "packed," i.e., a packing material may be
introduced into the fractured zone to reduce the amount of fine
particulants such as sand from being produced during the production
of hydrocarbons. The process of "packing" is well known in the art
and typically involves packing the well adjacent the unconsolidated
or loosely consolidated production interval, called gravel packing.
In a typical gravel pack completion, a sand control screen is
lowered into the wellbore on a workstring to a position proximate
the desired production interval. As described above, this sand
control screen may be included as a part of hydrajetting tool
assembly 10, typically below packing device 300. A fluid slurry
including a liquid carrier and a relatively coarse particulate
material, which is typically sized and graded and which is referred
to herein as gravel, is then pumped down the workstring and into
the well annulus formed between the sand control screen and the
perforated well casing or open hole production zone.
[0043] The liquid carrier either flows into the formation or
returns to the surface by flowing through a wash pipe or both. In
either case, the gravel is deposited around the sand control screen
to form the gravel pack, which is highly permeable to the flow of
hydrocarbon fluids but blocks the flow of the fine particulate
materials carried in the hydrocarbon fluids. As such, gravel packs
can successfully prevent the problems associated with the
production of these particulate materials from the formation.
[0044] In another embodiment of the present invention, the proppant
material, such as sand, is consolidated to better hold it within
the microfractures. Consolidation may be accomplished by any number
of conventional means, including, but not limited to, introducing a
resin coated proppant (RCP) into the microfractures.
[0045] Another operation possible using at least one embodiment of
the present invention is known to those of skill in the art as a
cement squeeze. Following perforation or fracturing, evaluation of
perforation or fracturing operation may be determined by the
operator to be inadequate. In such a situation, the operator may
wish to close the perforations or isolate formation 1150 from
wellbore 1100. Following the perforation or fracturing operation,
cement may be pumped down work string 12 and out nozzles 22 of
hydrajetting sub 20. After setting, the cement acts to close the
perforations of well casing 410 or isolate formation 1150 from
wellbore 1100.
[0046] Therefore, the present invention is well-adapted to carry
out the objects and attain the ends and advantages mentioned as
well as those which are inherent therein. While the invention has
been depicted, described, and is defined by reference to exemplary
embodiments of the invention, such a reference does not imply a
limitation on the invention, and no such limitation is to be
inferred. The invention is capable of considerable modification,
alteration, and equivalents in form and function, as will occur to
those ordinarily skilled in the pertinent arts and having the
benefit of this disclosure. The depicted and described embodiments
of the invention are exemplary only, and are not exhaustive of the
scope of the invention. Consequently, the invention is intended to
be limited only by the spirit and scope of the appended claims,
giving full cognizance to equivalents in all respects.
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