U.S. patent application number 12/724456 was filed with the patent office on 2010-09-30 for method for completing tight oil and gas reservoirs.
Invention is credited to Francois M. Auzerais, Curtis L. Boney, Austin Boyd, Marie Noelle Dessinges, Bruno Drochon, Ryan Hartman, Gregory Kubala, Bruce A. MacKay, Rod Shampine, John W. Still, Philip F. Sullivan, Don Williamson.
Application Number | 20100243242 12/724456 |
Document ID | / |
Family ID | 42782697 |
Filed Date | 2010-09-30 |
United States Patent
Application |
20100243242 |
Kind Code |
A1 |
Boney; Curtis L. ; et
al. |
September 30, 2010 |
METHOD FOR COMPLETING TIGHT OIL AND GAS RESERVOIRS
Abstract
A method and apparatus for processing a subterranean formation
comprising stimulating and fracturing a subterranean formation, and
drilling the subterranean formation wherein the drilling and
fracturing occurs without removing equipment for drilling from the
formation. A method and apparatus for drilling and fracturing a
subterranean formation, comprising a drill string assembly and a
hydraulic fracturing system, wherein the drill string and
fracturing system are in communication with a wellbore and wherein
the drill string and a fracture formed by the hydraulic fracturing
system are less than about 1000 feet apart. A method and apparatus
for processing a subterranean formation comprising fracturing a
subterranean formation using a hydraulic fracturing system and
drilling the subterranean formation using a drill string assembly
wherein the drilling and fracturing occurs without removing the
drill string from the formation, and wherein the fracturing occurs
via ports in the drill string assembly.
Inventors: |
Boney; Curtis L.; (Houston,
TX) ; Dessinges; Marie Noelle; (Chatte, FR) ;
Drochon; Bruno; (Cambridge, GB) ; Williamson;
Don; (Katy, TX) ; Sullivan; Philip F.;
(Bellaire, TX) ; Auzerais; Francois M.; (Boston,
MA) ; Still; John W.; (Katy, TX) ; Kubala;
Gregory; (Houston, TX) ; MacKay; Bruce A.;
(Sugar Land, TX) ; Hartman; Ryan; (Arlington,
MA) ; Boyd; Austin; (Ridgefield, CT) ;
Shampine; Rod; (Houston, TX) |
Correspondence
Address: |
SCHLUMBERGER TECHNOLOGY CORPORATION;David Cate
IP DEPT., WELL STIMULATION, 110 SCHLUMBERGER DRIVE, MD1
SUGAR LAND
TX
77478
US
|
Family ID: |
42782697 |
Appl. No.: |
12/724456 |
Filed: |
March 16, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61211194 |
Mar 27, 2009 |
|
|
|
Current U.S.
Class: |
166/250.01 ;
166/177.5; 166/278; 166/281; 166/308.1; 166/308.2; 166/308.6;
175/65 |
Current CPC
Class: |
E21B 43/26 20130101;
E21B 43/025 20130101 |
Class at
Publication: |
166/250.01 ;
166/308.1; 175/65; 166/281; 166/278; 166/308.6; 166/308.2;
166/177.5 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 7/00 20060101 E21B007/00; E21B 43/27 20060101
E21B043/27; E21B 43/02 20060101 E21B043/02; E21B 47/00 20060101
E21B047/00; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method for processing a subterranean formation, comprising:
stimulating and fracturing a subterranean formation; and drilling
the subterranean formation, wherein the drilling and fracturing
occurs without removing downhole drilling equipment from the
formation.
2. The method of claim 1, wherein the drilling and fracturing form
a conductive fracture using acid.
3. The method of claim 1, further comprising forming a seal along a
surface of the formation.
4. The method of claim 3, wherein the seal is temporary.
5. The method of claim 3, wherein the seal is placed during
drilling.
6. The method of claim 1, wherein the drilling occurs using a fluid
selected for its density and its ability to modify fluid
temperature.
7. The method of claim 1, further comprising introducing a
composition along the surface of the subterranean formation.
8. The method of claim 7, wherein the composition stabilizes the
surface of the subterranean formation.
9. The method of claim 7, wherein the composition has a stability
that is tailored to degrade over time.
10. The method of claim 7, wherein the composition comprises carbon
dioxide or nitrogen.
11. The method of claim 7, wherein the composition is
electrosensitive or magneto sensitive.
12. The method of claim 7, wherein the composition comprises a
material that melts below formation temperature.
13. The method of claim 7, wherein the composition comprises
crosslinked polymers.
14. The method of claim 1, wherein the fracturing comprises
proppant.
15. The method of claim 14, wherein the proppant comprises material
to make it swell, shrink, or form acid.
16. The method of claim 14, wherein the proppant comprises proppant
with multiple diameters.
17. The method of claim 1, wherein a filter cake is formed along a
surface of the subterranean formation.
18. The method of claim 17, wherein the filter cake comprises a
breaker material.
19. The method of claim 18, wherein the material is
encapsulated.
20. The method of claim 17, wherein the filter cake comprises a
material to decrease cake permeability.
21. The method of claim 17, wherein the material comprises latex or
an emulsion.
22. The method of claim 17, wherein the filter cake is tailored to
prevent or allow fracture.
23. The method of claim 17, wherein the filter cake is
self-diverting.
24. The method of claim 1, wherein the equipment comprises a drill
string.
25. The method of claim 1, further comprising controlling and/or
blocking the fluid return system.
26. The method of claim 1, wherein a pressure on the outer surface
of a drill bit is controlled.
27. The method of claim 1, further comprising pumping fluid through
a bypass, annulus, or a drill string.
28. The method of claim 1, further comprising collecting cuttings
via a drillstring or annulus.
29. The method of claim 1, further comprising introducing a packer
into the wellbore.
30. The method of claim 1, further comprising triggering the
fracturing by dropping a ball into the drillstring.
31. The method of claim 1, further comprising using optical fibers
to provide feedback to control the fracturing.
32. The method of claim 1, wherein the drilling occurs
horizontally, vertically, and/or with multiple branches.
33. The method of claim 1, further comprising measuring
microseismic, temperature, sonic, information and controlling the
fracturing and/or drilling using the information.
34. The method of claim 1, wherein the fracturing comprises
introducing a foam or an energized fluid into the wellbore.
35. The method of claim 1, wherein the fracturing occurs as a drill
string assembly is traveling away from a wellhead.
36. The method of claim 1, wherein the fracturing occurs as a drill
string assembly is traveling toward a wellhead.
37. An apparatus for drilling and fracturing a subterranean
formation, comprising: a drill string assembly; and a hydraulic
fracturing system, wherein the drill string and fracturing system
are in communication with a wellbore and wherein the drill string
and a fracture formed by the hydraulic fracturing system are less
than about 1000 feet apart.
38. The apparatus of claim 37, further comprising a packer.
39. The apparatus of claim 37, wherein the drill string is
configured to withstand exposure to hydraulic fracturing.
40. The apparatus of claim 37, wherein the hydraulic fracturing
system is configured to fracture one stage at a time.
41. The apparatus of claim 37, further comprising a seal that
encompasses a wellbore, drill string, and a hydraulic fracturing
fluid inlet port.
42. The apparatus of claim 37, wherein the drill string is
configured to deliver hydraulic fracturing fluid.
43. A method for processing a subterranean formation, comprising:
fracturing a subterranean formation using a hydraulic fracturing
system; and drilling the subterranean formation using a drill
string assembly, wherein the drilling and fracturing occurs without
removing the drill string from the formation, and wherein the
fracturing occurs via ports in the drill string assembly.
Description
PRIORITY
[0001] This application claims priority as a non provisional
application of U.S. Provisional Patent Application No. 61/211,194,
filed Mar. 27, 2009, which is hereby incorporated by reference in
its entirety.
BACKGROUND
[0002] Many geological formations require hydraulic stimulation to
produce hydrocarbons. Examples of formations that require hydraulic
stimulation would be tight gas sands such as the Cotton Valley of
East Texas, the Barnett Shale in Arkansas, and the Niobrara Sand in
Colorado. Such formations are usually hydraulically fractured after
the drilling process. The typical procedure would be to drill, then
case and cement the well, and then perforate the desired intervals
and hydraulically fracture them by injecting fluid into the
perforated interval at high pressure.
[0003] Completing tight gas and oil wells using hydraulic
fracturing and horizontal/deviated wellbores recovers the most
reserves in a shorter period of time with less cost than
conventional procedures and techniques. Conventional completions
normally have a wellbore that is drilled, the drilling assembly is
then removed from the wellbore, and the completion assembly is run
in the wellbore. After this, the completion or stimulation takes
places at each zone of interest. This process is very costly and
time consuming. Also, in fracturing operations, proppant is placed
in the fracture in order to keep the fracture open after pumping is
stopped. Efforts in the past have been made to ease the fracturing
operations such as modifying fluid or proppant properties to
optimize proppant placement. In any event, a system for increasing
the production of a subterranean formation with reduced process
steps is needed.
BRIEF DESCRIPTION OF THE FIGURES
[0004] FIG. 1 is a sectional view of an embodiment of a drill
string assembly and subterranean formation.
[0005] FIG. 2 is a schematic view of an embodiment of surface
equipment and wellbore configured for hydraulic fracturing.
[0006] FIG. 3 is a sectional view of a an embodiment of a drill
string assembly and a fracture in the subterranean formation.
[0007] FIG. 4 is a dimensional view of an embodiment of a wellbore
positioned through several fractures in the subterranean
formation.
[0008] FIG. 5 is a dimensional view of an embodiment of wellbores
positioned through several fractures in the subterranean
formation.
[0009] FIG. 6 is a dimensional view of an alternative embodiment of
wellbores in a subterranean formation.
[0010] FIG. 7 is a plot of pressure versus time during an
embodiment of a hydraulic fracturing operation.
[0011] FIG. 8 is a dimensional view of an embodiment of a wellbore
and drilling assembly positioned to fracture the subterranean
formation.
[0012] FIG. 9 is a dimensional view of an alternative embodiment of
a wellbore and drilling assembly positioned to fracture the
subterranean formation.
[0013] FIG. 10 is a schematic diagram of an embodiment of a
tangential well-bore stress.
SUMMARY
[0014] Embodiments of the invention relate to a method and
apparatus for processing a subterranean formation comprising
stimulating and fracturing a subterranean formation and drilling
the subterranean formation, wherein the drilling and fracturing
occurs without removing downhole drilling equipment from the
formation. In some embodiments, the drilling and fracturing form a
conductive fracture using acid. Some embodiments may benefit from
forming a seal along a surface of the formation. In some
embodiments, the seal is temporary and/or the seal is placed during
drilling. In some embodiments, the drilling accurs using a fluid
selected for its density, lubricity, frictional properties, sonic
travel properties, carry proppant, formation damage and its ability
to modify fluid temperature.
[0015] Some embodiments may benefit from introducing a composition
along the surface of the subterranean formation. In some
embodiments, the composition stabilizes the surface of the
subterranean formation. In some embodiments, the composition has a
stability that is tailored to degrade over time. In some
embodiments, the composition comprises carbon dioxide or nitrogen.
In some embodiments, the composition is electrosensitive or magneto
sensitive. In some embodiments, the composition comprises a
material that melts below formation temperature. In some
embodiments, the composition comprises crosslinked polymers.
[0016] In some embodiments, the fracturing comprises proppant. In
some embodiments, the proppant comprises material to make it swell,
shrink, or form acid. In some embodiments, the proppant comprises
proppant with multiple diameters.
[0017] In some embodiments, a filter cake is formed along a surface
of the subterranean formation. In some embodiments, the filter cake
comprises a breaker material. In some embodiments, the material is
encapsulated. In some embodiments, the filter cake comprises a
material to decrease cake permeability. In some embodiments, the
material comprises latex or an emulsion. In some embodiments, the
filter cake is tailored to prevent or allow fracture. In some
embodiments, the filter cake is self-diverting.
[0018] In some embodiments, the equipment comprises a drill string.
Some embodiments may benefit from controlling and/or blocking the
fluid return system. In some embodiments, a pressure on the outer
surface of a drill bit is controlled. Some embodiments may benefit
from pumping fluid through a bypass, annulus, or a drill string.
Some embodiments may benefit from collecting cuttings via a
drillstring or annulus. Some embodiments may benefit from
introducing a packer into the wellbore. Some embodiments may
benefit from triggering the fracturing by dropping a ball into the
drillstring. Some embodiments may benefit from using electrical
line or optical fibers to provide feedback to control the
fracturing.
[0019] In some embodiments, the drilling occurs horizontally,
vertically, and/or with multiple branches. Some embodiments may
benefit from measuring microseismic, temperature, and/or sonic
information and controlling the fracturing and/or drilling using
the information. Some embodiments may benefit from introducing
afoam or an energized fluid into the wellbore.
[0020] In some embodiments, the fracturing occurs as the drill
string assembly is traveling away from a wellhead. In some
embodiments, the fracturing occurs as the drill string assembly is
traveling toward a wellhead.
[0021] Embodiments of the invention relate to a method and
apparatus for drilling and fracturing a subterranean formation
comprising a drill string assembly and a hydraulic fracturing
system, wherein the drill string and fracturing system are in
communication with a wellbore and wherein the drill string and a
fracture formed by the hydraulic fracturing system are less than
about 1000 feet apart. Some embodiments may benefit from a packer.
In some embodiments, drill string is configured to withstand
exposure to hydraulic fracturing. In some embodiments, the
hydraulic fracturing system is configured to fracture one stage at
a time. Some embodiments may benefit from a seal that encompasses a
wellbore, drill string assembly, and a hydraulic fracturing fluid
inlet port. In some embodiments, the drill string assembly is
configured to deliver hydraulic fracturing fluid.
[0022] Embodiments of the invention relate to a method and
apparatus for processing a subterranean formation comprising
fracturing a subterranean formation using a hydraulic fracturing
system and drilling the subterranean formation using a drill string
assembly, wherein the drilling and fracturing occurs without
removing the drill string from the formation, and wherein the
fracturing occurs via ports in the drill string.
DETAILED DESCRIPTION
[0023] A method for fracturing while drilling is desirable for
increased efficiency and reduced costs. Creating subterranean
fractures without removing the drilling equipment from a wellbore
eliminates individual process steps such as drilling, casing,
completing, and perforating. This technique enables fracturing
operations and uses less hardware for completion in the wellbores.
Throughout this application, reference is made to fracturing a
formation. In this application, unless indicated otherwise,
fracturing may encompass stimulating a formation or providing a
matrix treatment to the formation as well as fracturing a
formation.
Mechanical Equipment
[0024] Drilling
[0025] Any drilling equipment could be used for the drilling aspect
of embodiments of this invention. The equipment may be selected for
its resilient properties over a high pressure regime and upon
exposure to a variety of chemical processes, mechanical stress
created by drilling, fracturing, and proppant placement, and/or
high temperatures. At a minimum, the drilling equipment should
include a drillbit. Further, the drilling equipment may include
protective shields and/or electrical components designed to
withstand harsh conditions. For example, some embodiments may
benefit from the couplers described in U.S. Pat. Nos. 6,866,306 and
6,641,434, which are hereby incorporated by reference. Also, the
drilling equipment may contain nozzles or other fluid delivery
mechanisms to deliver drilling fluid and/fracturing fluid and/or
other fluids.
[0026] FIG. 1 includes a downhole drilling assembly that includes
downhole drilling equipment and illustrates a wellsite system in
which embodiments of the present invention may be employed. The
wellsite can be onshore or offshore. In this exemplary system, a
borehole 11 is formed in subsurface formations by rotary drilling
in a manner that is well known. Embodiments of the invention can
also use directional drilling, as will be described
hereinafter.
[0027] A drill string 12 is suspended within the borehole 11 and
has a bottomhole assembly 100 which includes a drill bit 105 at its
lower end. The surface system includes platform and derrick
assembly 10 positioned over the borehole 11, the assembly 10
including a rotary table 16, kelly 17, hook 18 and rotary swivel
19. The drill string 12 is rotated by the rotary table 16,
energized by means not shown, which engages the kelly 17 at the
upper end of the drill string. The drill string 12 is suspended
from a hook 18, attached to a traveling block (also not shown),
through the kelly 17 and a rotary swivel 19 which permits rotation
of the drill string relative to the hook. A top drive system could
alternatively be used.
[0028] In the example of some embodiments, the surface system
further includes drilling fluid or mud 26 stored in a pit 27 formed
at the well site. A pump 29 delivers the drilling fluid 26 to the
interior of the drill string 12 via a port in the swivel 19,
causing the drilling fluid to flow downwardly through the drill
string 12 as indicated by the directional arrow 8. The drilling
fluid exits the drill string 12 via ports in the drill bit 105, and
then circulates upwardly through the annulus region between the
outside of the drill string and the wall of the borehole, as
indicated by the directional arrows 9. In this manner, the drilling
fluid lubricates the drill bit 105 and carries formation cuttings
up to the surface as it is returned to the pit 27 for
recirculation. The drilling fluid may also be cooled by injecting
cooling liquids, fluids, or gases near the pump 29 or the port in
the swivel 19.
[0029] The bottom hole assembly 100 of the illustrated embodiment a
logging-while-drilling (LWD) module 120, a measuring-while-drilling
(MWD) module 130, a roto-steerable system and motor, and drill bit
105.
[0030] The LWD module 120 is housed in a special type of drill
collar and can contain one or a plurality of logging tools. More
than one LWD and/or MWD module can be employed, e.g. as represented
at 120A (References throughout to a module at the position of 120
can alternatively mean a module at the position of 120A as well.).
The LWD module includes measuring, processing, and storing
information capabilities, as well as the ability to communicate
with the surface equipment. In some embodiments, the LWD module
includes a pressure measuring device.
[0031] The MWD module 130 is also housed in a special type of drill
collar and can contain one or more devices for measuring
characteristics of the drill string and drill bit. The MWD tool
further includes an apparatus (not shown) for generating electrical
power to the downhole system. This may typically include a mud
turbine generator powered by the flow of the drilling fluid, it
being understood that other power and/or battery systems may be
employed. In some embodiments, the MWD module includes one or more
of the following types of measuring devices: a weight-on-bit
measuring device, a torque measuring device, a vibration measuring
device, a shock measuring device, a stick slip measuring device, a
direction measuring device, and an inclination measuring
device.
[0032] The placement of wires in drill pipes for carrying signals
has been studied. Some early approaches to a wired drill string are
disclosed in U.S. Pat. Nos. 4,126,848, 3,957,118, and 3,807,502 and
in the publication "Four Different Systems Used for MWD," W. J.
McDonald, The Oil and Gas Journal, pages 115-124, Apr. 3, 1978.
[0033] Using inductive couplers located at the pipe joints has also
been studied. The following disclose use of inductive couplers in a
drill string: U.S. Pat. No. 4,605,268; Russian Federation published
patent application 2140527, filed Dec. 18, 1997; Russian Federation
published patent application 2040691, filed Feb. 14, 1992; and WO
Publication 90/14497A2. Also, see U.S. Pat. Nos. 5,052,941,
4,806,928, 4,901,069, 5,531,592, 5,278,550; and 5,971,072.
[0034] U.S. Pat. Nos. 6,641,434 and 6,866,306, are both hereby
incorporated by reference and describe a wired drill pipe joint
that is for reliably transmitting measurement data in high-data
rates, bidirectionally, between a surface station and locations in
the borehole. The '434 and '306 patents disclose a low-loss wired
pipe joint in which conductive layers reduce signal energy losses
over the length of the drill string by reducing resistive losses
and flux losses at each inductive coupler. The wired pipe joint is
robust in that the wired pipe joint remains operational in the
presence of gaps in the conductive layer.
[0035] A particularly advantage is controlled steering or
"directional drilling." In this embodiment, a roto-steerable
subsystem 150 is provided. Directional drilling is the intentional
deviation of the wellbore from the path it would naturally take. In
other words, directional drilling is the steering of the drill
string so that it travels in a desired direction. Directional
drilling is advantageous in offshore drilling because it enables
many wells to be drilled from a single platform. Directional
drilling also enables horizontal drilling through a reservoir.
Horizontal drilling enables a longer length of the wellbore to
traverse the reservoir, which increases the production rate from
the well. A directional drilling system may also be used in
vertical drilling operation as well. Often the drill bit will veer
off of a planned drilling trajectory because of the unpredictable
nature of the formations being penetrated or the varying forces
that the drill bit experiences. When such a deviation occurs, a
directional drilling system may be used to put the drill bit back
on course.
[0036] Directional drilling includes the use of a rotary steerable
system ("RSS"). The RSS includes rotating the drill string from the
surface and downhole devices cause the drill bit to drill in the
desired direction. Rotating the drill string greatly reduces the
likelihood of the drill string getting hung up or stuck during
drilling. Rotary steerable drilling systems for drilling deviated
boreholes into the earth may be generally classified as either
"point-the-bit" systems or "push-the-bit" systems.
[0037] In the point-the-bit system, the axis of rotation of the
drill bit is deviated from the local axis of the bottom hole
assembly in the general direction of the new hole. The hole is
propagated in accordance with a three point geometry defined by
upper and lower stabilizer touch points and the drill bit. The
angle of deviation of the drill bit axis coupled with a finite
distance between the drill bit and lower stabilizer results in the
non-collinear condition required for a curve to be generated. There
are many ways in which this may be achieved including a fixed bend
at a point in the bottom hole assembly close to the lower
stabilizer or a flexure of the drill bit drive shaft distributed
between the upper and lower stabilizer. In its idealized form, the
drill bit is not required to cut sideways because the bit axis is
continually rotated in the direction of the curved hole. Examples
of point-the-bit type rotary steerable systems, and how they
operate are described in United States Patent Application
Publication Number 2001/0052428 and U.S. Pat. Nos. 6,401,842,
6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610; and
5,113,953, which are all hereby incorporated by reference.
[0038] In the push-the-bit rotary steerable system there is usually
no specially identified mechanism to deviate the bit axis from the
local bottom hole assembly axis. Instead, the requisite
non-collinear condition is achieved by causing either or both of
the upper or lower stabilizers to apply an eccentric force or
displacement in a direction that is preferentially orientated with
respect to the direction of hole propagation. Again, there are many
ways in which this may be achieved, including non-rotating (with
respect to the hole) eccentric stabilizers (displacement based
approaches) and eccentric actuators that apply force to the drill
bit in the desired steering direction. Steering is achieved by
creating non co-linearity between the drill bit and at least two
other touch points. In its idealized form the drill bit is required
to cut sideways in order to generate a curved hole. Examples of
push-the-bit type rotary steerable systems and how they operate are
described in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185;
6,089,332; 5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763;
5,520,255; 5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein
incorporated by reference.
[0039] In some embodiments, the drilling motor may be top drive
(from a rotary table). In some embodiments, the motor may be driven
at the bit and feature some modification such as using a static
screen isolating tools from the wear and tear of hydraulic
fracturing. In some embodiments, the drill string may be partially
rotating. In some embodiments, the drill components may need to be
specially configured to resist being lodged into the wellbore
during drilling or fracturing, which may be especially important
during directional drilling.
[0040] Coiled Tubing
[0041] Coiled tubing has long been used in well operations in order
to place desirable fluids such as acids, cement and the like in a
well utilizing a relatively simple apparatus comprising a long
length of tubing, often as long as 25,000 feet, wound onto a large
spool or reel. In coiled tubing operations, tubing from the reel is
fed into the wellbore utilizing an injector mechanism which is well
known in the art. Fluids can be fed through a fitting on the tubing
reel, through the tubing to a tool disposed on the inserted end of
the coiled tubing within the well. In some embodiments, coiled
tubing with drilling capabilities may be used in addition to or in
place of drilling equipment.
[0042] Fracturing
[0043] Fracturing a subterranean formation with a drilling string
in the wellbore requires equipment that has been tailored for use
with a wellbore that may not include casing or completion. For
example, some surface equipment at the well head or wellbore casing
or cement may not be present. A choke line, bleedoff, and/or
pressure seal may be configured to protect the drill string. High
pressure pumps, blending equipment, proppant storage and delivery,
and other components of the system may need to be streamlined or
aligned to provide individual stages of treatment instead of
multiple stages. That is, less pumps or other equipment may be
needed for some embodiments of the invention. FIG. 2 provides a
schematic diagram of how the equipment may be arranged. Especially,
FIG. 2 illustrates that the number of pumps and other surface
equipment may be reduced to provide one stage at a time fracturing
treatments instead of multiple stages at one time.
[0044] Fracture tanks 201, transfer tanks 202, proppant feeders
203, proppant conveyer 204, hopper 205, liquid transport trailer
206, fluid blending unit 207, proppant blender 208, job monitoring
unit 209, pumpers 210, manifold trailer 211, nitrogen pumpers 212,
carbon dioxide transports 213, booster 214, and pumper 215,
densitometer 216, flowmeter 217, pressure transducer 218, and
pumper 219 may all be configured to provide fracturing while
drilling to the well 220. At the well 220, the wellhead (not
pictured) may be configured to administer drill equipment and
fracturing equipment simultaneously.
[0045] Packers
[0046] In some embodiments, packers may be used to isolate sections
of the wellbore. The packer may be mechanical, inflatable, or
swellable. To provide a seal, the packer may mechanically squeeze,
expand upon exposure to a fluid pressure, and/or contain a material
that swells upon exposure to a fluid or other conditions. The
packers may be mechanical or chemical or both. They may have a
means of activation and/or release that is mechanical or chemical
or both. In some embodiments, the packers may be temporary packers.
In alternative embodiments, the packers may remain in place until
mechanically removed. In some embodiments, the packers may be
deployed to isolate regions of the wellbore or wellhead from flow
backup from a hydraulic fracturing operation or from a drilling
operation. In some embodiments, the packers may have mechanisms to
keep from getting stuck in undesired regions of the wellbore.
[0047] Ball.
[0048] In some embodiments, a ball may be introduced into the
wellbore to trigger drilling or fracturing. Aspects of the use of a
ball are described in more detail below.
Chemistry
[0049] Embodiments of the invention may relate to several chemical
processes that enhance the effectiveness of fracturing or drilling
or both. Drilling fluid, fracturing fluid, pills, filter cake,
proppant, tracers, annular protection fluid, and cooling systems
may be employed to facilitate embodiments of the invention. In some
embodiments, acid fracturing may be employed, such as the
fracturing described in U.S. Pat. No. 7,644,761, 7,306,041 and
6,828,280, which are all three incorporated by reference herein in
their entirety.
[0050] Drilling fluid may comprise components to significantly
increasing the mud weight or otherwise controlling the drilling
fluid density. As drilling proceeds (especially for a horizontal
well), some embodiments may create zones of various permeability
along the newly generated well faces by weighing the drilling mud
with additives. The concentration of additives (from 0 to a certain
percentage by weight of the drilling mud) would form a filter cake
of increasing permeability. The drilling fluid is cooled by
injecting liquid CO.sub.2, nitrogen, or other liquid gas at the
surface to cool the drilling fluid sufficiently to create thermally
induced fractures in the desired geological formations near the
drill bit.
[0051] Adding a material to the drilling fluid that melts at some
temperature above ambient and below formation temperatures would
significantly increase the impact on the formation by allowing the
drilling fluid to carry significantly more energy. When the
drilling fluid with these materials reaches the formation area the
materials would melt, absorbing significant energy and cooling the
formation more than would be possible with fluids alone. Further,
these materials could be chosen such that the liquids generated by
melting the materials would provide other useful chemical activity
downhole (such as producing liquid acid, gelling, breaking,
crystallization of something in the fluid, or other processes).
[0052] The hydraulic fractures may be created using water, acid,
oil, hydrocarbon gas, carbon dioxide, nitrogen gas, and any
combination of these. The carrier fluid can generally be any liquid
carrier suitable for use in oil and gas producing wells. One such
liquid carrier is water. The liquid carrier can comprise water, can
consist essentially of water, or can consist of water. Water will
typically be a major component by weight of the fluid. The water
can be potable or non-potable water. The water can be brackish or
contain other materials typical of sources of water found in or
near oil fields.
[0053] A salt may be present in the fluid carrier. The salt can be
present naturally if brine is used, or can be added to the fluid
carrier. For example, it is possible to add to water; any salt,
such as an alkali metal or alkali earth metal salt (NaCO.sub.3,
NaCl, KCl, etc.). The salt is generally present in weight percent
concentration between about 0.1% to about 5%, from about 1% to
about 3% by weight. One useful concentration is about 2% by weight.
Salt maybe used in higher concentrations to make a more dense fluid
and thus enabling higher pressures at the fracturing point and
lower pressures at the surface. This makes for less hydraulic
horsepower and expensive pressure control equipment.
[0054] The crosslinked polymer can generally be any crosslinked
polymers. The polymer viscosifier can be a metal-crosslinked
polymer. Suitable polymers for making the metal-crosslinked polymer
viscosifiers include, for example, polysaccharides such as
substituted galactomannans, such as guar gums, high-molecular
weight polysaccharides composed of mannose and galactose sugars, or
guar derivatives such as hydroxypropyl guar (HPG),
carboxymethylhydroxypropyl guar (CMHPG) and carboxymethyl guar
(CMG), hydrophobically modified guars, guar-containing compounds,
and synthetic polymers. Crosslinking agents based on boron,
titanium, zirconium or aluminum complexes are typically used to
increase the effective molecular weight of the polymer and make
them better suited for use in high-temperature wells.
[0055] Other suitable classes of polymers effective as viscosifiers
include polyvinyl polymers, polymethacrylamides, cellulose ethers,
lignosulfonates, and ammonium, alkali metal, and alkaline earth
salts thereof. More specific examples of other typical water
soluble polymers are acrylic acid-acrylamide copolymers, acrylic
acid-methacrylamide copolymers, polyacrylamides, partially
hydrolyzed polyacrylamides, partially hydrolyzed
polymethacrylamides, polyvinyl alcohol, polyalkyleneoxides, other
galactomannans, heteropolysaccharides obtained by the fermentation
of starch-derived sugar and ammonium and alkali metal salts
thereof.
[0056] Cellulose derivatives are used to a smaller extent, such as
hydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC),
carboxymethylhydroxyethylcellulose (CMHEC) and
carboxymethycellulose (CMC), with or without crosslinkers. Xanthan,
diutan, and scleroglucan, three biopolymers, have been shown to
have excellent proppant-suspension ability even though they are
more expensive than guar derivatives and therefore have been used
less frequently, unless they can be used at lower
concentrations.
[0057] In other embodiments, the crosslinked polymer is made from a
crosslinkable, hydratable polymer and a delayed crosslinking agent,
wherein the crosslinking agent comprises a complex comprising a
metal and a first ligand selected from the group consisting of
amino acids, phosphono acids, and salts or derivatives thereof.
Also the crosslinked polymer can be made from a polymer comprising
pendant ionic moieties, a surfactant comprising oppositely charged
moieties, a clay stabilizer, a borate source, and a metal
crosslinker. Said embodiments are described in U.S. Patent
Publications US2008-0280790 and US2008-0280788 respectively, each
of which are incorporated herein by reference.
[0058] Linear (not cross-linked) polymer systems may be used.
However, in some cases, may not achieve the full benefits because
they may require more concentration. Any suitable crosslinked
polymer system may be used, including for example, those which are
delayed, optimized for high temperature, optimized for use with sea
water, buffered at various pH's, and optimized for low temperature.
Any crosslinker may be used, for example boron, titanium,
zirconium, aluminum and the like. Suitable boron crosslinked
polymers systems include by non-limiting example, guar and
substituted guars crosslinked with boric acid, sodium tetraborate,
and encapsulated borates; borate crosslinkers may be used with
buffers and pH control agents such as sodium hydroxide, magnesium
oxide, sodium sesquicarbonate, and sodium carbonate, amines (such
as hydroxyalkyl amines, anilines, pyridines, pyrimidines,
quinolines, and pyrrolidines, and carboxylates such as acetates and
oxalates) and with delay agents such as sorbitol, aldehydes, and
sodium gluconate. Suitable zirconium crosslinked polymer systems
include by non-limiting example, those crosslinked by zirconium
lactates (for example sodium zirconium lactate), triethanolamines,
2,2'-iminodiethanol, and with mixtures of these ligands, including
when adjusted with bicarbonate. Suitable titanates include by
non-limiting example, lactates and triethanolamines, and mixtures,
for example delayed with hydroxyacetic acid. Any other chemical
additives may be used or included provided that they are tested for
compatibility with the viscoelastic surfactant. For example, some
of the standard crosslinkers or polymers as concentrates usually
contain materials such as isopropanol, n-propanol, methanol or
diesel oil.
[0059] The viscoelastic surfactant can generally be any
viscoelastic surfactant. The surfactant is present in a low weight
percent concentration. Some suitable concentrations of surfactant
are about 0.001% to about 1.5% by weight, from about 0.01% to about
0.75% by weight, or even about 0.25%, about 0.5% or about 0.75% by
weight.
[0060] The VES may be selected from the group consisting of
cationic, anionic, zwitterionic, amphoteric, nonionic and
combinations thereof. Some non-limiting examples are those cited in
U.S. Pat. Nos. 6,435,277 (Qu et al.) and 6,703,352 (Dahayanake et
al.), each of which are incorporated herein by reference. The
viscoelastic surfactants, when used alone or in combination, are
capable of forming micelles that form a structure in an aqueous
environment that contribute to the increased viscosity of the fluid
(also referred to as "viscosifying micelles"). These fluids are
normally prepared by mixing in appropriate amounts of VES suitable
to achieve the desired viscosity. The viscosity of VES fluids may
be attributed to the three dimensional structure formed by the
components in the fluids. When the concentration of surfactants in
a viscoelastic fluid significantly exceeds a critical
concentration, and in most cases in the presence of an electrolyte,
surfactant molecules aggregate into species such as micelles, which
can interact to form a network exhibiting viscous and elastic
behavior.
[0061] Non-limiting examples of suitable viscoelastic surfactants
useful for viscosifying some fluids include cationic surfactants,
anionic surfactants, zwitterionic surfactants, amphoteric
surfactants, nonionic surfactants, and combinations thereof.
[0062] In general, particularly suitable zwitterionic surfactants
have the formula:
RCONH--(CH.sub.2).sub.a(CH.sub.2CH.sub.2O).sub.m(CH.sub.2).sub.b--N.sup.-
+(CH.sub.3).sub.2--(CH.sub.2).sub.a'(CH.sub.2CH.sub.2O).sub.m'(CH.sub.2).s-
ub.b'COO.sup.-
in which R is an alkyl group that contains from about 11 to about
23 carbon atoms which may be branched or straight chained and which
may be saturated or unsaturated; a, b, a', and b' are each from 0
to 10 and m and m' are each from 0 to 13; a and b are each 1 or 2
if m is not 0 and (a+b) is from 2 to 10 if m is 0; a' and b' are
each 1 or 2 when m' is not 0 and (a'+b') is from 1 to 5 if m is 0;
(m+m') is from 0 to 14; and CH.sub.2CH.sub.2O may also be
OCH.sub.2CH.sub.2.
[0063] In an embodiment of the invention, a zwitterionic
surfactants of the family of betaine is used. Two suitable examples
of betaines are BET-0 and BET-E. The surfactant in BET-O-30 is
shown below; one chemical name is oleylamidopropyl betaine. It is
designated BET-O-30 because as obtained from the supplier (Rhodia,
Inc. Cranbury, N.J., U.S.A.) it is called Mirataine BET-O-30
because it contains an oleyl acid amide group (including a
C.sub.17H.sub.33 alkene tail group) and contains about 30% active
surfactant; the remainder is substantially water, sodium chloride,
and propylene glycol. An analogous material, BET-E-40, is also
available from Rhodia and contains an erucic acid amide group
(including a C.sub.21H.sub.41 alkene tail group) and is
approximately 40% active ingredient, with the remainder being
substantially water, sodium chloride, and isopropanol. VES systems,
in particular BET-E-40, optionally contain about 1% of a
condensation product of a naphthalene sulfonic acid, for example
sodium polynaphthalene sulfonate, as a rheology modifier, as
described in U.S. Patent Application Publication No. 2003-0134751.
The surfactant in BET-E-40 is also shown below; one chemical name
is erucylamidopropyl betaine. As-received concentrates of BET-E-40
were used in the experiments reported below, where they will be
referred to as "VES". BET surfactants, and other VES's that are
suitable for the embodiments according to the invention, are
described in U.S. Pat. No. 6,258,859. According to that patent, BET
surfactants make viscoelastic gels when in the presence of certain
organic acids, organic acid salts, or inorganic salts; in that
patent, the inorganic salts were present at a weight concentration
up to about 30%. Co-surfactants may be useful in extending the
brine tolerance, and to increase the gel strength and to reduce the
shear sensitivity of the VES-fluid, in particular for BET-O-type
surfactants. An example given in U.S. Pat. No. 6,258,859 is sodium
dodecylbenzene sulfonate (SDBS), also shown below. Other suitable
co-surfactants include, for example those having the SDBS-like
structure in which x=5-15; other co-surfactants are those in which
x=7-15. Still other suitable co-surfactants for BET-O-30 are
certain chelating agents such as trisodium
hydroxyethylethylenediamine triacetate. The rheology enhancers of
the embodiments according to the invention may be used with
viscoelastic surfactant fluid systems that contain such additives
as co-surfactants, organic acids, organic acid salts, and/or
inorganic salts.
##STR00001##
[0064] Some embodiments use betaines; for example BET-E-40.
Although experiments have not been performed, it is believed that
mixtures of betaines, especially BET-E-40, with other surfactants
are also suitable. Such mixtures are within the scope of
embodiments of the invention.
[0065] Other betaines that are suitable include those in which the
alkene side chain (tail group) contains 17-23 carbon atoms (not
counting the carbonyl carbon atom) which may be branched or
straight chained and which may be saturated or unsaturated, n=2-10,
and p=1-5, and mixtures of these compounds. Some betaines are those
in which the alkene side chain contains 17-21 carbon atoms (not
counting the carbonyl carbon atom) which may be branched or
straight chained and which may be saturated or unsaturated, n=3-5,
and p=1-3, and mixtures of these compounds. These surfactants are
used at a concentration of about 0.5 to about 10%, or from about 1
to about 5%, or even from about 1.5 to about 4.5%.
[0066] Exemplary cationic viscoelastic surfactants include the
amine salts and quaternary amine salts disclosed in U.S. Pat. Nos.
5,979,557, and 6,435,277 which have a common Assignee as the
present application and which are hereby incorporated by reference.
Examples of suitable cationic viscoelastic surfactants include
cationic surfactants having the structure:
R.sub.1N.sup.+(R.sub.2)(R.sub.3)(R.sub.4)X.sup.-
in which R.sub.1 has from about 14 to about 26 carbon atoms and may
be branched or straight chained, aromatic, saturated or
unsaturated, and may contain a carbonyl, an amide, a retroamide, an
imide, a urea, or an amine; R.sub.2, R.sub.3, and R.sub.4 are each
independently hydrogen or a C.sub.1 to about C.sub.6 aliphatic
group which may be the same or different, branched or straight
chained, saturated or unsaturated and one or more than one of which
may be substituted with a group that renders the R.sub.2, R.sub.3,
and R.sub.4 group more hydrophilic; the R.sub.2, R.sub.3 and
R.sub.4 groups may be incorporated into a heterocyclic 5- or
6-member ring structure which includes the nitrogen atom; the
R.sub.2, R.sub.3 and R.sub.4 groups may be the same or different;
R.sub.1, R.sub.2, R.sub.3 and/or R.sub.4 may contain one or more
ethylene oxide and/or propylene oxide units; and X.sup.- is an
anion. Mixtures of such compounds are also suitable. As a further
example, R.sub.1 is from about 18 to about 22 carbon atoms and may
contain a carbonyl, an amide, or an amine, and R.sub.2, R.sub.3,
and R.sub.4 are the same as one another and contain from 1 to about
3 carbon atoms.
[0067] Cationic surfactants having the structure
R.sub.1N.sup.+(R.sub.2)(R.sub.3)(R.sub.4)X.sup.- may optionally
contain amines having the structure R.sub.1N(R.sub.2)(R.sub.3). It
is well known that commercially available cationic quaternary amine
surfactants often contain the corresponding amines (in which
R.sub.1, R.sub.2, and R.sub.3 in the cationic surfactant and in the
amine have the same structure). As received commercially available
VES surfactant concentrate formulations, for example cationic VES
surfactant formulations, may also optionally contain one or more
members of the group consisting of alcohols, glycols, organic
salts, chelating agents, solvents, mutual solvents, organic acids,
organic acid salts, inorganic salts, oligomers, polymers,
co-polymers, and mixtures of these members. They may also contain
performance enhancers, such as viscosity enhancers, for example
polysulfonates, for example polysulfonic acids, as described in
U.S. Pat. No. 7,084,095 which is hereby incorporated by
reference.
[0068] Another suitable cationic VES is erucyl bis(2-hydroxyethyl)
methyl ammonium chloride, also known as (Z)-13
docosenyl-N-N-bis(2-hydroxyethyl) methyl ammonium chloride. It is
commonly obtained from manufacturers as a mixture containing about
60 weight percent surfactant in a mixture of isopropanol, ethylene
glycol, and water. Other suitable amine salts and quaternary amine
salts include (either alone or in combination in accordance with
the invention), erucyl trimethyl ammonium chloride;
N-methyl-N,N-bis(2-hydroxyethyl) rapeseed ammonium chloride; oleyl
methyl bis(hydroxyethyl) ammonium chloride;
erucylamidopropyltrimethylamine chloride, octadecyl methyl
bis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl)
ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide;
cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methyl
bis(hydroxyethyl) ammonium salicylate; cetyl methyl
bis(hydroxyethyl) ammonium 3,4,-dichlorobenzoate; cetyl
tris(hydroxyethyl) ammonium iodide; cosyl dimethyl hydroxyethyl
ammonium bromide; cosyl methyl bis(hydroxyethyl) ammonium chloride;
cosyl tris(hydroxyethyl) ammonium bromide; dicosyl dimethyl
hydroxyethyl ammonium bromide; dicosyl methyl bis(hydroxyethyl)
ammonium chloride; dicosyl tris(hydroxyethyl) ammonium bromide;
hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecyl
isopropyl bis(hydroxyethyl) ammonium iodide; and cetylamino,
N-octadecyl pyridinium chloride.
[0069] Many fluids made with viscoelastic surfactant systems, for
example those containing cationic surfactants having structures
similar to that of erucyl bis(2-hydroxyethyl) methyl ammonium
chloride, inherently have short re-heal times and the rheology
enhancers of the embodiments according to the invention may not be
needed except under special circumstances, for example at very low
temperature.
[0070] Amphoteric viscoelastic surfactants are also suitable.
Exemplary amphoteric viscoelastic surfactant systems include those
described in U.S. Pat. No. 6,703,352, for example amine oxides.
Other exemplary viscoelastic surfactant systems include those
described in U.S. Pat. Nos. 6,239,183; 6,506,710; 7,060,661;
7,303,018; and 7,510,009 for example amidoamine oxides. These
references are hereby incorporated in their entirety. Mixtures of
zwitterionic surfactants and amphoteric surfactants are suitable.
An example is a mixture of about 13% isopropanol, about 5%
1-butanol, about 15% ethylene glycol monobutyl ether, about 4%
sodium chloride, about 30% water, about 30% cocoamidopropyl
betaine, and about 2% cocoamidopropylamine oxide.
[0071] The viscoelastic surfactant system may also be based upon
any suitable anionic surfactant. In some embodiments, the anionic
surfactant is an alkyl sarcosinate. The alkyl sarcosinate can
generally have any number of carbon atoms. Alkyl sarcosinates can
have about 12 to about 24 carbon atoms. The alkyl sarcosinate can
have about 14 to about 18 carbon atoms. Specific examples of the
number of carbon atoms include 12, 14, 16, 18, 20, 22, and 24
carbon atoms. The anionic surfactant is represented by the chemical
formula:
R.sub.1CON(R.sub.2)CH.sub.2X
wherein R.sub.1 is a hydrophobic chain having about 12 to about 24
carbon atoms, R.sub.2 is hydrogen, methyl, ethyl, propyl, or butyl,
and X is carboxyl or sulfonyl. The hydrophobic chain can be an
alkyl group, an alkenyl group, an alkylarylalkyl group, or an
alkoxyalkyl group. Specific examples of the hydrophobic chain
include a tetradecyl group, a hexadecyl group, an octadecentyl
group, an octadecyl group, and a docosenoic group.
[0072] To provide the ionic strength for the desired micelle
formation, in some cases, the treatment fluids of the embodiments
according to the invention may comprise a water-soluble salt.
Adding a salt may help promote micelle formation for the
viscosification of the fluid in some instances. In some
embodiments, the aqueous base fluid may contain the water-soluble
salt, for example, where saltwater, a brine, or seawater is used as
the aqueous base fluid. Suitable water-soluble salts may comprise
lithium, ammonium, sodium, potassium, cesium, magnesium, calcium,
or zinc cations, and chloride, bromide, iodide, formate, nitrate,
acetate, cyanate, or thiocyanate anions. Examples of suitable
water-soluble salts that comprise the above-listed anions and
cations include, but are not limited to, ammonium chloride, lithium
bromide, lithium chloride, lithium formate, lithium nitrate,
calcium bromide, calcium chloride, calcium nitrate, calcium
formate, sodium bromide, sodium chloride, sodium formate, sodium
nitrate, potassium chloride, potassium bromide, potassium nitrate,
potassium formate, cesium nitrate, cesium formate, cesium chloride,
cesium bromide, magnesium chloride, magnesium bromide, zinc
chloride, and zinc bromide.
[0073] All thicknened fluids may contain a breaker to reduce
fracture formation damage or to facilitate the return of the
fracturing fluids from the fracture as normally used.
[0074] The composition also typically contains proppants. The
selection of a proppant involves many compromises imposed by
economical and practical considerations. Criteria for selecting the
proppant type, size, and concentration is based on the needed
dimensionless conductivity, and can be selected by a skilled
artisan. Such proppants can be natural or synthetic (including but
not limited to glass beads, ceramic beads, sand, and bauxite),
coated, or contain chemicals; more than one can be used
sequentially or in mixtures of different sizes or different
materials. The proppant may be resin coated, or pre-cured resin
coated, provided that the resin and any other chemicals that might
be released from the coating or come in contact with the other
chemicals of the Invention are compatible with them. Proppants and
gravels in the same or different wells or treatments can be the
same material and/or the same size as one another and the term
"proppant" is intended to include gravel in this discussion. In
general the proppant used will have an average particle size of
from about 0.15 mm to about 2.39 mm (about 8 to about 100 U.S.
mesh), more particularly, but not limited to 0.25 to 0.43 mm (40/60
mesh), 0.43 to 0.84 mm (20/40 mesh), 0.84 to 1.19 mm (16/20), 0.84
to 1.68 mm (12/20 mesh) and 0.84 to 2.39 mm (8/20 mesh) sized
materials. Normally the proppant will be present in the slurry in a
concentration of from about 0.12 to about 0.96 kg/L, or from about
0.12 to about 0.72 kg/L, or from about 0.12 to about 0.54 kg/L. The
fluid may also contain other enhancers or additives.
[0075] In other embodiments, the composition may further comprise
an additive for maintaining and/or adjusting pH (e.g., pH buffers,
pH adjusting agents, etc.). For example, the additive for
maintaining and/or adjusting pH may be included in the treatment
fluid so as to maintain the pH in, or adjust the pH to, a desired
range and thereby maintain, or provide, the necessary ionic
strength to form the desired micellar structures. Examples of
suitable additives for maintaining and/or adjusting pH include, but
are not limited to, sodium acetate, acetic acid, sodium carbonate,
potassium carbonate, sodium bicarbonate, potassium bicarbonate,
sodium or potassium diacetate, sodium or potassium phosphate,
sodium or potassium hydrogen phosphate, sodium or potassium
dihydrogen phosphate, sodium hydroxide, potassium hydroxide,
lithium hydroxide, combinations thereof, derivatives thereof, and
the like. The additive for adjusting and/or maintaining pH may be
present in the treatment fluids of the embodiments according to the
invention in an amount sufficient to maintain and/or adjust the pH
of the fluid. One of ordinary skill in the art, with the benefit of
this disclosure, will recognize the appropriate additive for
maintaining and/or adjusting pH and amount thereof to use for a
chosen application.
[0076] In some embodiments, the composition may optionally comprise
additional additives, including, but not limited to, acids, fluid
loss control additives, gas, corrosion inhibitors, scale
inhibitors, catalysts, clay control agents, biocides, friction
reducers, combinations thereof and the like. For example, in some
embodiments, it may be desired to foam the composition using a gas,
such as air, nitrogen, or carbon dioxide. In one certain
embodiment, the composition may contain a particulate additive,
such as a particulate scale inhibitor.
[0077] In some embodiments of the invention, the composition may be
used for carrying out a variety of subterranean treatments, where a
viscosified treatment fluid may be used, including, but not limited
to, drilling operations, fracturing treatments, and completion
operations (e.g., gravel packing) In some embodiments, the
treatment fluids may be used in treating a portion of a
subterranean formation. In certain embodiments, the composition may
be introduced into a well bore that penetrates the subterranean
formation. Optionally, the treatment fluid further may comprise
particulates and other additives suitable for treating the
subterranean formation. For example, the treatment fluid may be
allowed to contact the subterranean formation for a period of time
sufficient to reduce the viscosity of the treatment fluid. In some
embodiments, the treatment fluid may be allowed to contact
hydrocarbons, formations fluids, and/or subsequently injected
treatment fluids, thereby reducing the viscosity of the treatment
fluid. After a chosen time, the treatment fluid may be recovered
through the well bore.
[0078] In certain embodiments, the treatment fluids may be used in
fracturing treatments. In the fracturing embodiments, the
composition may be introduced into a well bore that penetrates a
subterranean formation at or above a pressure sufficient to create
or enhance one or more fractures in a portion of the subterranean
formation. Generally, in the fracturing embodiments, the
composition may exhibit viscoelastic behavior which may be due.
Optionally, the treatment fluid further may comprise particulates
and other additives suitable for the fracturing treatment. After a
chosen time, the treatment fluid may be recovered through the well
bore.
[0079] The composition according to the invention provides the
following benefits when fracturing permeable formations in the 50
to 90 degC temperature range, or even the 54 to 82 degC temperature
range: higher viscosity at a given temperature with lower polymer
concentration (71.1 degC at a shear rate of 100 s/s and 25 minutes
at temperature--prior art fluid 130 cp, fluid according to the
invention 210 cp); improved fluid loss control (static leakoff test
in an 80 mD core at71.1 degC--prior art fluid spurt loss 4.81,
C.sub.w=0.006088, fluid according to the invention spurt loss 2.61,
C.sub.w=0.001598); improved shear recovery (viscosity at 100/s
after 2 minutes shear at 100/s--prior art fluid 100 cp, fluid
according to the invention 175 cp); less sensitive to the presence
of surfactants and de-emulsifiers.
[0080] The methods of the invention are also suitable for gravel
packing, or for fracturing and gravel packing in one operation
(called, for example frac and pack, frac-n-pack, frac-pack, StimPac
treatments, or other names), which are also used extensively to
stimulate the production of hydrocarbons, water and other fluids
from subterranean formations. These operations involve pumping a
slurry of "proppant" (natural or synthetic materials that prop open
a fracture after it is created) in hydraulic fracturing or "gravel"
in gravel packing In low permeability formations, the goal of
hydraulic fracturing is generally to form long, high surface area
fractures that greatly increase the magnitude of the pathway of
fluid flow from the formation to the wellbore. In high permeability
formations, the goal of a hydraulic fracturing treatment is
typically to create a short, wide, highly conductive fracture, in
order to bypass near-wellbore damage done in drilling and/or
completion, to ensure good fluid communication between the rock and
the wellbore and also to increase the surface area available for
fluids to flow into the wellbore.
[0081] Gravel is also a natural or synthetic material, which may be
identical to, or different from, proppant. Gravel packing is used
for "sand" control. Sand is the name given to any particulate
material from the formation, such as clays, that could be carried
into production equipment. Gravel packing is a sand-control method
used to prevent production of formation sand, in which, for example
a steel screen is placed in the wellbore and the surrounding
annulus is packed with prepared gravel of a specific size designed
to prevent the passage of formation sand that could foul
subterranean or surface equipment and reduce flows. The primary
objective of gravel packing is to stabilize the formation while
causing minimal impairment to well productivity. Sometimes gravel
packing is done without a screen. High permeability formations are
frequently poorly consolidated, so that sand control is needed;
they may also be damaged, so that fracturing is also needed.
Therefore, hydraulic fracturing treatments in which short, wide
fractures are wanted are often combined in a single continuous
("frac and pack") operation with gravel packing For simplicity, in
the following we may refer to any one of hydraulic fracturing,
fracturing and gravel packing in one operation (frac and pack), or
gravel packing, and mean them all.
[0082] In a particular embodiment, fluids that comprise emulsions
may be selected. The invert emulsion may be of the reversible type,
whereby the invert emulsion may be converted from a water-in-oil
type emulsion to an oil-in-water type emulsion upon exposure to
acid, for example. Such reversible oil-based fluids include those
described in U.S. Pat. Nos. 6,218,342, 6,806,233 6,790,811,
7,527,097, 7,238,646, 6,989,354, 7,178,550, 6,608,006, 7,152,697,
7,178,594, 7,222,672, 7,238,646 and 7,3777,721, for example, which
are herein incorporated by reference in their entirety.
[0083] In some embodiments, a degradable material such as
polylactic or polyglycolic acid may be used. More information about
degradable materials may be found in U.S. Pat. Nos. 7,380,600,
7,565,929, and 7,581,590 which are all three incorporated by
reference herein.
[0084] Any fracture connecting to the wellbore (either a natural
fracture or a created fracture) may be temporarily sealed during
some part of the process. Otherwise the open fractures will "steal"
fluid from the wellbore and hinder further progress in either
drilling or fracturing. Some embodiments relate to ways to
chemically seal the fractures, reverse the sealing to make the
fractures reconnect to the wellbore, and chemical tracers to verify
that the process is occurring as desired downhole.
[0085] Solutions to seal at least temporarily the fractures created
are: [0086] Use swellable proppant: once placed in the fracture the
proppant would swell and decrease the permeability of the proppant
pack. Once the drilling tool is pumped out the hole, a pill could
be used to shrink back the proppant to its original shape. The pill
could dissolve the swellable proppant by pH or by any other
chemical means. [0087] Use proppant that would automatically slowly
release a chemical that would shrink the proppant. It could be a
slowly dissolvable material that coat the proppant such as PVA or
PVOH. With the time and temperature the coated layer would dissolve
and leave the core of the proppant intact. The proppant pack
conductivity would be resumed. [0088] An alternative is to use a
double layer coating made of an internal oxidizer and an external
oxidizable material. With temperature and time the oxidizer could
be triggered to oxidize the external layer and leave the core of
the proppant intact. [0089] Another elegant approach would be to
use different size of proppant and use the CRETE concept: weight
the proppant stages with a smaller size particle proppant that is
entirely dissolvable (particles of PVA or particles of oxidizers or
particles of a slowly soluble salt) but which size completely plugs
the fracture faces by invading the pores left by the bigger size
proppant. This would be specifically manageable with oil based mud
where the presence of the oil would decrease significantly the
solubility of the small size particles. When drilling is complete
the particles would dissolve and the proppant pack conductivity
would be resumed. [0090] Use swellable proppant: once placed in the
fracture the proppant would swell and decrease the permeability of
the proppant pack. Once the drilling tool is pumped out the hole, a
pill could be used to shrink back the proppant to its original
shape. The pill could dissolve the swellable proppant by pH or by
any other chemical means. Alternatively, unswelling or degradation
can be triggered by dissolution of solid acid in the proppant pack
or wellbore. [0091] Use proppant that would automatically slowly
release a chemical that would shrink the proppant. it could be a
slowly dissolvable material that coat the proppant such as PVA or
PVOH. With the time and temperature the coated layer would dissolve
and leave the core of the proppant intact. The proppant pack
conductivity would be resumed. [0092] An alternative is to use a
double layer coating made of an internal oxidizer and an external
oxidizable material. With temperature and time the oxidizer could
be triggered to oxidize the external layer and leave the core of
the proppant intact. [0093] Another elegant approach would be to
use different size of proppant and use a concept based on the
CRETE.TM. system available from Schlumberger Technology Corporation
of Sugar Land, Tex.: weight the proppant stages with a smaller size
particle proppant that is entirely dissolvable (particles of PVA or
particles of oxidizers or particles of a slowly soluble salt) but
which size completely plugs the fracture faces by invading the
pores left by the bigger size proppant. This would be specifically
manageable with oil based mud where the presence of the oil would
decrease significantly the solubility of the small size particles.
When drilling is complete the particles would dissolve and the
proppant pack conductivity would be resumed. [0094] In one
approach, CleanSEAL.TM. technology, which is a technology platform
that may be commercial obtained from Schlumberger Technology
Corporation of Sugar Land, Tex., may be used as a temporary sealant
that is acid degradable. CleanSEAL.TM. is comprised of crosslinked
HEC, which breaks rapidly on contact with acid or slowly over time
by degradation. A CleanSEAL.TM. squeeze pill could be placed to
seal a fracture entrance at the wellbore. CleanSEAL.TM. could be
placed in conjunction with solid acid. Such a squeeze treatment can
also temporarily fill natural fractures connected to the wellbore
or created fractures. Systems can be developed both for breaking
with dissolved acid either by an acid-breaking polymer or by an
internal trigger that is acid-responsive. An effective seal with
CleanSEAL.TM. would allow us to clean up the wellbore by swabbing
and circulating acid.
[0095] Annular protection fluid will have the properties to prevent
the stimulation fluid from moving up the wellbore. These properties
come from the combination of a heavy weight or hydrostatic
pressure, high viscosity or yield strength, and or particulates
that prevent flow into a permeable or thief zone. This fluid maybe
captured and reused to lower waste and cost.
[0096] Tracers may be placed in the CleanSEAL.TM. material so one
can chemically detect the cleanup process. This detection can even
take place downhole with chemical detector instrumentation. Ways to
exploit the use of solid acid as it eliminates the need to
circulate live acid in a drilling system are also desirable.
[0097] In some embodiments, fracturing fluid may comprise
lubricating ingredients to help remove the drill string.
Methods
[0098] FIG. 3 illustrates an embodiment of a drill string assembly
301 in a wellbore 302 in a subterranean formation 303. The drill
string assembly 301 may contain a port or ports 304 that release
fluid from the drill string assembly 301 at high pressure to
fracture the formation 303, forming a fracture 305. In some
embodiments, the port 304 may release an acid, solid latened slurry
or other chemical to notch the formation 303 to facilitate
fracturing in a later process step as the drill string moves
through the wellbore or drills the wellbore. In some embodiments,
the port 304 may provide a mechanical means such as a slip, dog, or
bit to form a notch. In some embodiments, the port 304 may provide
a perforating mechanism. In some embodiments, the port 304 may
provide proppant to pack the fracture 305. In some embodiments, the
port 304 may provide viscous material to seal the fracture 305 as
described in more detail below. In some embodiments, the port 304
may be activated by dropping a ball (not pictured in FIG. 3) down
the annulus (not pictured).
[0099] Initially, the drill string assembly 301 drills the wellbore
302 in the subterranean formation 303. As it reaches a region that
may benefit from hydraulic fracturing, packers 306 and/or packers
307 may be deployed and fluid is introduced through the ports 304
to form a fracture 305. The packers 306 and 307 may be used to
protect the wellbore 302 and/or the drill bit assembly 307 and/or
mechanical, chemical, electrical, sonic, or other instrumentation
and communication devices housed in the drill string assembly
components 308. The drill string components 308 may also collect,
administer, and direct the drill string assembly 301 via logging
while drilling information. For example, the components 308 may be
used to identify and direct the drill string assembly 301 to notch
regions of the formation 302 that would benefit from fracturing.
Additional process steps such as additional fracturing may be
desired to fracture regions initially identified with a notch. The
components 308 may also comprise microseismic measurement
capability.
[0100] FIG. 3 illustrates an embodiment wherein the fracturing
occurs after the drill string assembly 301, such as downhole
drilling equipment, has formed a wellbore, but alternative
embodiments are possible. That is, fracturing could occur ahead of
the drilling assembly 308. Further, this process appears to be
occurring as the drilling assembly 308 travels down the wellbore
302, but the process could also be occurring as the drilling
assembly 308 returns from the depths of the wellbore 302 to the
surface of the wellbore 308 toward the wellhead (not pictured in
FIG. 3).
[0101] In fact, in some embodiments, the advantage of ports 304 is
that the fracturing may occur above the drill bit assembly 308,
providing high pressure and ease of operation down the annulus 309.
That is, it may be desirable to continue drilling while fracturing.
In some embodiments, the packers 306 may be formed of a degradable
material selected to protect or seal the drill bit assembly 307.
Alternatively, in some embodiments, a seal may be formed of
degradable material that acts as packer 306 in place of or in
addition to seal 306.
[0102] In some embodiments, fluid may be pumped through ports such
as jets in the drill bit assembly 307. In some preferred
embodiments, fluid may be pumped through ports 304 above the drill
bit assembly 307. In some embodiments wherein the packers 307 may
or may not be deployed, fluids may be pumped through the annulus
309 to produce the fracture 305. In some embodiments, coiled tubing
and the annulus may be used to fracture and drill. In some
embodiments, the drilling assembly and annulus may be used to
fracture and drill.
[0103] In some embodiments, partial return of material may be
selected to cool the bit and to remove tailings. In some
embodiments, the fracture may not be sealed and it may be used for
underbalanced drilling, that is, intentionally trying to get flow
or not blocking flow may be desirable.
[0104] In some embodiments, one approach uses horizontal or highly
deviated wellbore(s). The wellbore(s) is hydraulically fractured
several times along its length. The fractures are made orthogonal
to the wellbore and extend into the reservoir to at least near the
boundary edge of the desired drainage. These long fractures, while
very conductive as compared to the formation, are not conductive
enough to meet the drainage goals of the reservoir. This makes
these fractures more economical to create because they use fewer
resources. After the fractures are created, additional wellbores or
branches from the original well bore are added out further in the
formation and intersecting the fractures. These additional
wellbores can then drain the formation through the fractures that
were created earlier.
[0105] The wellbore itself can be vertical or horizontal or highly
deviated up or down and with or without multibraching wellbore(s).
The wellbore(s) can be hydraulically fractured several times along
its length. These fractures are connected directly to the wellbore
and extend into the reservoir. This makes these fractures more
economical to create as they can be created as soon as the wellbore
is drilled lowering time and associated cost. One embodiment of the
invention provides a means to generate preferential zones for
future fractures as the horizontal well is drilled.
[0106] In some embodiments, thermal stress can be significant in
high Young's modulus formations. Accordingly, embodiments of the
invention provide a method to hydraulically stimulate "tight" high
Young's Modulus formations while drilling by significantly cooling
the drilling fluid. The method to cool the drilling fluid is to
inject liquid CO.sub.2 into the drilling fluid while drilling in
the formation that requires hydraulic stimulation Alternatively,
the hydraulic fracture could be induced by significantly lowering
the temperature of the drilling fluid in the zone of interest. If
the drilling fluid is cooler the than the formation temperature,
the hoop stresses at the well-bore can become tensile and the
injection pressure required to initiate a fracture can be reduced
by several thousand psi. Such fractures are created while drilling
by cooling the drilling fluid which would induce an extra tensile
force on the borehole wall, in proportion to the difference in
temperature between borehole fluid and the geological
formation.
[0107] An additional embodiment creates a self diverting filter
cake while drilling in a horizontal well, in order to generate
fractures in the entire drilled zone at the same time when the zone
has been entirely drilled.
[0108] In some embodiments, as drilling is complete, the entire
length of the horizontal well could be fractured, and the zones
with the highest permeability would be preferentially fractured
while the zone with the lowest permeability would not accept
fracturing fluid. Given that the entire zone should be a pay zone,
the exact placement of the mud cakes with the highest permeability
should not be critical.
[0109] This process enables economical flow of hydrocarbon fluids
or gas in reservoirs that have a combination of the reservoir
pressure, fluid properties and formation permeability result in
very low flow to the wellbore(s).
[0110] FIG. 4 is a dimensional view of an embodiment of a wellbore
401 positioned through several fractures 402 in a reservoir 403 in
the subterranean formation. In a simple block reservoir, this
process uses a primary wellbore 401 that would be horizontal on
near horizontal through the actual reservoir 403. The wellbore 401
would then be hydraulically fractured many times (more than 2
fractures 402) using conventional techniques used in the industry
to complete the well 404 and isolate the different fractures 402
while they are being made from each other. The fractures 402 would
be left conductive to the reservoir fluids and gas as shown by
fluid flow arrows 405 in FIG. 4, but not conductive enough to
satisfactorily drain the reservoir 403 from volumes, time or
economics.
[0111] FIG. 5 is a dimensional view of an embodiment of wellbores
501. The fractures 502 would then be accessed by another
wellbore(s) 501 further into the reservoir 503. This additional
wellbore 501 would enable the produced fluid less restriction to
flow by shorting the distance down the fracture it must travel to a
wellbore 501. The wellbore 501 would then open a high capacity
venue for the fluid to flow out. The additional wellbore(s) 501 may
come from another lateral leg from the same wellbore that is used
to make the fractures 502 from or other wellbores in or near the
reservoir 503. The vertical position of the extra wellbores 501
maybe positioned either up or down from the others to drain a
different fluid or gas (as illustrated by the fluid flow lines 504)
from the reservoir 503 than the other one(s). An example one be the
lowest wellbore 501 would be water from the fracture and thus
freeing up fracture conductivity for the gas to up and out.
[0112] These extra drain holes 501 can be completed without the
cost of isolation completion as it will not be necessary to do so
and this lowers cost. If it is desirable to drill the drain hole
prior to fracturing, then they can be filled with polymer, drilling
fluid, or any material that will help prevent the flow of frac
fluid down the wellbore while fracturing. This process is best used
in wells where the rock 505 around the wellbore is sufficient
strength to produce the well without collapse.
[0113] FIG. 6 is a dimensional view of an alternative embodiment of
wellbores 601 in a subterranean formation 602. That is, the
vertical legs of the wellbores 601 may be selected to drain regions
of the reservoir 603 based upon locations of the fractures 604
and/or flow patterns of the water, oil, or gas illustrated by the
flow lines 605.
[0114] FIG. 7 shows a typical sequence of pressure versus time
during a hydraulic fracturing operation. The fracture initiation
pressure is the maximum pressure shown on the plot above and is
determined by the hoop stresses on the formation, the tensile
strength of the formation and the formation pore pressure. In low
porosity, low permeability or "tight" formations the fracture
initiation pressure may be so high that it would not be feasible to
attempt fracturing while drilling. By cooling the drilling fluid so
that it is significantly less than the formation temperature, the
fracture initiation pressure could be reduced significantly as
shown in the following diagram and equations and it would then be
feasible to create a tensile fracture.
[0115] The tangential well-bore stress .sigma..sub..theta..theta.
as illustrated in some embodiments by FIG. 10 is given by;
.sigma..sub..theta..theta.=.sigma..sub.H+.sigma..sub.h-2(.sigma..sub.H-.-
sigma..sub.h)cos 2.theta.-2P.sub.o-(P.sub.b-P.sub.o) (1)
where .sigma..sub.H is the maximum horizontal stress, .sigma..sub.h
is the minimum horizontal stress, .theta. is the angle relative to
maximum horizontal stress P.sub.o is the formation pore pressure
P.sub.b is the borehole hydraulic pressure
[0116] In the case where .theta.=0 or 180 which is where the
tensile forces will be greatest and in formations where
permeability is very low and we can neglect the formation pore
pressure equation (1) reduces to
.sigma..sub..theta..theta.=3.sigma..sub.h-.sigma..sub.H-P.sub.b
(2)
[0117] If the borehole fluid temperature is less than the formation
temperature there will be an extra tensile force
.sigma..sub.T=-.alpha.E.DELTA.T/1-.gamma. (3)
where .sigma..sub.T is the thermal stress .alpha. is the linear
coefficient of thermal expansion of the formation E is the Young's
Modulus of the formation .DELTA.T is the temperature difference
between borehole fluid and formation .gamma. is the Poisson's ratio
of the formation Including equation 3 in equation 2 we now have
.sigma..sub..theta..theta.=3.sigma..sub.h-.sigma..sub.H+.sigma..sub.T-P.-
sub.b (4)
Where .sigma..sub.T is a negative or tensile force if the drilling
fluid is cooler than the formation.
[0118] If the sum of all the terms on the right hand side of
equation 4 are negative (tensile) and exceed the tensile strength
of the formation, a fracture will initiate. The tensile strength of
most rock formations is assumed to be 1/12 of the compressive
strength. For example, in a formation with a compressive strength
of 24000 psi we'd expect a tensile strength of 2000 psi. If the
minimum horizontal stress were 5000 psi and the maximum horizontal
stress were 6000 psi, and the hydraulic pressure from the drilling
fluid were 4000 psi, a fracture could be initiated if the thermal
stress exceeded 3000 psi. For formations with high Young's Modulus,
the tensile forces due to thermal stress are of the order of 1000
psi for every 10 degrees Celsius the drilling fluid is cooler than
the formation temperature. Thus if the mud could be cooled to 30
degrees Celsius cooler than formation temperature, a tensile
fracture would be initiated.
[0119] The thermal stress is highest in zones of high Young's
Modulus, and tight, low porosity zones which are difficult to
conventionally hydraulically stimulate can have Young's moduli
sufficiently high that the thermal stress would facilitate creating
a tensile fracture. This could be achieved by significantly
increasing the mud weight or the pump pressure while drilling
through the interval requiring hydraulic fracturing.
[0120] In some embodiments, a packer may be placed above the drill
bit. Judicial placement of a packer above the drill bit would
improve the efficiency further. By cooling the borehole fluid
sufficiently, a tensile fracture could be initiated without
exceeding the pressure rating of the packer. In some embodiments, a
packer may be activated when the drilling fluid is cooled
sufficiently and/or before fracturing occurs.
[0121] An alternative therefore to fracturing while drilling is to
drill the entire well and generate fractures from different zones
at the end of the drilling operation all in once at the same time.
The drilling and fracturing fluids can be different and the
drilling equipment can be at least partially removed (in case of an
horizontal well) and not damaged by the proppant stages. This
implies, however, the use of a diversion technique in order to
fracture all the zones at once.
[0122] An additional embodiment of a fracturing while drilling
process is also provided. The process depends on the idea of
drilling some distance in to the reservoir, fracturing a zone,
temporarily sealing a zone, then resuming drilling. The process
repeats until the desired length of the wellbore has been drilled
and fractured.
[0123] The process, as illustrated in some embodiments by FIG. 8
and in some embodiments by FIG. 9, is as follows.
[0124] 1) Once drilled through or partially through zone of
interest or reservoir 801, circulate annular protection fluid to
the annulus.
[0125] 2) prop ball 802 and displace with cutting or formation
breakdown fluid.
[0126] 3) Open cutting ports (not shown) and cut or break down
formation 805 to initiate the fracture 804.
[0127] 4) propand displace larger ball 803 to open frac ports (not
shown).
[0128] 5) Fracture well.
[0129] 6) Pull pipe 806 up to shear the annular protection fluid
807 and circulate or reverse out of the wellbore 808. Reverse balls
803, 802 to surface at this time.
[0130] 7) Run drilling pipe 806 back to bottom to close ports.
[0131] 8) Continue drilling to next interval 809.
[0132] 9) Repeat steps 1 through 8 until all zones are stimulated.
(FIG. 6)
[0133] 10) Come out of the wellbore with the drilling assembly 810.
Flow well to produce
[0134] In the above process, the drilling assembly maybe pulled
back up the hole for up to 1000' to insure the security of the
assembly in case of wellbore collapse.
[0135] In an alternative embodiment, one could place an additive
such as a latex or an emulsion that would replace temporarily the
mud cake or that would be placed on the top of the mud cake and
decrease locally the permeability of the mud cake. This additive
would be placed in stages either of various concentrations or in an
on and off manner. When the additive is present the mud cake would
be of very low permeability since the additive would form an
impermeable film of the surface of the mud cake, when the additive
is not present the mud cake would be of standard permeability value
encountered with standard mud cakes.
[0136] When the entire zone is drilled, the drilling equipment
would be removed leaving a drilling well with zones of lowest
permeability than others. As fracturing fluid would be pumped in
the horizontal well at a pressure sufficient to crack the rock
wherever the permeability is high enough different zones would be
fractured. The zones of lowest permeability would not allow fluid
entry and would not be fractured.
[0137] An alternative embodiment may place in the additive a
responsive material such as a material that is electro-sensitive or
magneto-sensitive. As the drilling equipment is removed from the
horizontal well from the tip of the well to the wellbore, a signal
would be sent through the drilling bit on the way out that would
activate the additive wherever it is placed and for example degrade
the mud cake for preferential fluid entry. The sequence described
above would be inverted but the principle remains the same. [0138]
As the well is drilled place in various amounts (or on/off
sequence) an additive in the drilling mud that would be placed
inside the mud cake whenever present. [0139] When the entire zone
is drilled, the drilling bit on the way back would activate the
additive by sending electric pulses (range of action short enough
to be able to activate the additive) or pressure pulses. Wherever
the additive is present the mud cake would be removed. [0140]
Wherever the mud cake has been removed, the local permeability
would be much higher enabling preferential entry of the fracturing
fluids, ie. The additives would be diverting the fracturing fluid
in the entire drilled well.
[0141] The responsive material could be a drilling mud cake breaker
encapsulated in a pressure sensitive membrane or encapsulated in
magnetic material that would revert or change conformation with a
local magnetic field.
[0142] An important note is that the material does not have to
invade the entire fracture but it could be used in the first few
inches of the fracture length as long as the seal is strong enough
to not be open again while the next fractures are open.
[0143] Another note is that the described inventions here could be
used in other (and maybe more relevant) applications than
fracturing while drilling such as means of diverting agents, or
sand control issues.
[0144] An important note is that the material does not have to
invade the entire fracture but it could be used in the first few
inches of the fracture length as long as the seal is strong enough
to not be open again while the next fractures are open.
[0145] In some embodiments, bypassed zones may be the target for
combined drilling and fracturing. Instead of "starting over" with a
new well from the surface, one option is to drill off horizontally
from existing wells. This can be done either with coiled tubing
drilling or with rotary steerable technology. Ideally, this
horizontal section will be fractured in numerous places to maximize
connectivity of the reservoir to the wellbore.
[0146] The above processes can be also used to stimulate the
formation where acid or other chemical that will dissolve the rock,
such as HCl with Carbonate formation, to stimulate will be injected
below fracturing pressures. This etches the face of an already
present fracture or wormhole a small channel some distance from the
wellbore out into the formation.
[0147] Advantages
[0148] A technique that requires less fracturing operations and
less hardware for completion in the wellbores will reduce cost of
field development and speed up production. This will reduce cost of
field development and speed up production.
[0149] This process enables economical flow of hydrocarbon fluids
or gas in reservoirs that have a combination of the reservoir
pressure, fluid properties and formation permeability result in
very low flow to the wellbore(s).
[0150] The methods herein could be used in other applications than
fracturing while drilling such as means of diverting agents, or
resolving sand control issues.
[0151] In formations where an open hole completion is desired, such
as horizontal wells in tight formations, fracturing while drilling
would lead to significant savings in rig time and operational
efficiency.
[0152] The preceding description has been presented with reference
to presently preferred embodiments of the invention. Persons
skilled in the art and technology to which this invention pertains
will appreciate that alterations and changes in the described
structures and methods of operation can be practiced without
meaningfully departing from the principle, and scope of this
invention. Accordingly, the foregoing description should not be
read as pertaining only to the precise structures described and
shown in the accompanying drawings, but rather should be read as
consistent with and as support for the following claims, which are
to have their fullest and fairest scope.
* * * * *