U.S. patent application number 10/249523 was filed with the patent office on 2003-11-06 for means and method for assessing the geometry of a subterranean fracture during or after a hydraulic fracturing treatment.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to Ayoub, Joseph, Fitzgerald, Peter, Jardine, Stuart.
Application Number | 20030205376 10/249523 |
Document ID | / |
Family ID | 29251160 |
Filed Date | 2003-11-06 |
United States Patent
Application |
20030205376 |
Kind Code |
A1 |
Ayoub, Joseph ; et
al. |
November 6, 2003 |
Means and Method for Assessing the Geometry of a Subterranean
Fracture During or After a Hydraulic Fracturing Treatment
Abstract
The present invention relates to methods of fracturing a
subterranean formation including the step of pumping at least one
device actively transmitting data that provide information on the
device position, and further comprising the step of assessing the
fracture geometry based on the positions of said at least one
device or pumping metallic elements, preferably as proppant agents,
and further locating the position of said metallic elements with a
tool selected from the group consisting of magnetometers,
resistivity tools, electromagnetic devices and ultra-long arrays of
electrodes. The invention allows monitoring of the fracture
geometry and proppant placement.
Inventors: |
Ayoub, Joseph; (Katy,
TX) ; Jardine, Stuart; (Houston, TX) ;
Fitzgerald, Peter; (Paris, FR) |
Correspondence
Address: |
Schlumberger Technology Corporation
110 Schlumberger Drive
MD-1
Sugar Land
TX
77478
US
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
110 Schlumberger Drive MD-1
Sugar Land
TX
|
Family ID: |
29251160 |
Appl. No.: |
10/249523 |
Filed: |
April 16, 2003 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60374217 |
Apr 19, 2002 |
|
|
|
Current U.S.
Class: |
166/254.2 ;
166/250.1; 73/152.03 |
Current CPC
Class: |
E21B 49/00 20130101;
E21B 47/09 20130101; E21B 43/26 20130101; E21B 47/01 20130101 |
Class at
Publication: |
166/254.2 ;
166/250.1; 166/280; 73/152.03 |
International
Class: |
E21B 043/267; E21B
047/09; E21B 047/12 |
Claims
1. A method of fracturing a subterranean formation comprising
injecting a fracturing fluid, into a hydraulic fracture created
into a subterranean formation, wherein at least a portion of the
fracturing fluid comprises at least one device actively
transmitting data that provide information on the device position,
and further comprising the step of assessing the fracture geometry
based on the positions of said devices.
2. The method of claim 1, wherein said devices are electronic
devices.
3. The method of claim 2, wherein said devices are radio frequency
or other EM wave transmitters.
4. The method of claim 1, wherein said devices are--acoustic
devices.
5. The method of claim 4, wherein said devices are ultrasonic
transceivers.
6. The method of claim 1, wherein at least one device is pumped
during the pad stage and at least one device is pumped during the
tail portion.
7. The method of claim 1, wherein said devices also transmit
information as to the temperature of the surrounding formation.
8. The method of claim 1, wherein said devices also transmit
information as to the pressure.
9. The method of claim 1, wherein a plurality of devices is
injected, said devices organized in a wireless network.
10. The method of claim 1, wherein the devices are electronic
transmitters and the method further includes the deployment of at
least an antenna.
11. The method of claim 10, wherein antennas are mounted on
non-conductive balls that are pumped with the fluid and seat in
some of the perforations relaying the signals from sensors behind
the casing wall.
12. The method of claim 10, wherein the antenna is trailed by the
transmitter within the fracture while the transmitter is
pumped.
13. The method of claim 1, where the device is an optical fiber
deployed through the perforation.
14. The method of claim 13, wherein the optical fiber is further
deployed through the fracture.
15. A method of fracturing a subterranean formation comprising
injecting a fracturing fluid, into a hydraulic fracture created
into a subterranean formation, wherein at least a portion of the
fracturing fluid comprises metallic elements and further comprising
the step of locating the position of said metallic elements with a
tool selected from the group consisting of magnetometers,
resistivity tools, electromagnetic devices and ultra-long arrays of
electrodes.
16. The method of claim 15 wherein said metallic material comprises
elongated particles having a length to equivalent diameter greater
than 5.
17. The method of claim 16, wherein said particles have a shape
with a lengthaspect ration greater than 10.
18. The method of claim 16, wherein said elongated particles have a
wire-segment shape.
19. The method of claim 16, wherein said elongated particles are in
a material selected from the group consisting of iron, ferrite, low
carbon steel, stainless steel and iron-alloys.
20. The method of claim 16, where said elongated particles consists
of metallic wires having a hardness of between 45 and 55
Rockwell.
21. The method of claim 16, wherein said elongated particles are
resin-coated.
22. The method of claim 16, wherein said elongated particles have a
length of between 1 and 25 mm.
23. The method of claim 22, wherein said elongated particles have a
length of between about 2 and about 15 mm.
24. The method of claim 16, wherein said elongated particles have a
diameter of between about 0.1 mm and about 1 mm.
25. The method of claim 16, wherein said individual particles of
said elongated particulate material have a diameter of between
about 0.2 mm and about 0.5 mm.
26. The method of claim 1, wherein the geometry of the fracture is
monitored in real-time during the hydraulic fracturing
treatment.
27. The method of claim 15, wherein the geometry of the fracture is
monitored in real-time during the hydraulic fracturing treatment.
Description
BACKGROUND OF INVENTION
[0001] This invention relates generally to the art of hydraulic
fracturing in subterranean formations and more particularly to a
method and means for assessing the fracture geometry during or
after the hydraulic fracturing.
[0002] Hydraulic fracturing is a primary tool for improving well
productivity by placing or extending cracks or channels from the
wellbore to the reservoir. This operation is essentially performed
by hydraulically injecting a fracturing fluid into a wellbore
penetrating a subterranean formation and forcing the fracturing
fluid against the formation strata by pressure. The formation
strata or rock is forced to crack, creating or enlarging one or
more fractures. Proppant is placed in the fracture to prevent the
fracture from closing and thus, provide improved flow of the
recoverable fluid, i.e., oil, gas or water.
[0003] The proppant is thus used to hold the walls of the fracture
apart to create a conductive path to the wellbore after pumping has
stopped. Placing the appropriate proppant at the appropriate
concentration to form a suitable proppant pack is thus critical to
the success of a hydraulic fracture treatment.
[0004] The geometry of the hydraulic fracture placed affects
directly the efficiency of the process and the success of the
operation. This geometry is generally inferred using models and
data interpretation, but to date, no direct measurements are
available. The present invention is aimed at obtaining more direct
measurements of the fracture geometry (e.g. length, height away
from the wellbore).
[0005] The fracture geometry is often inferred through use of
models and interpretation of pressure measurements. Occasionally,
temperature logs and/or radioactive tracer logs are used to infer
fracture height near the wellbore. Microseismic events generated in
the vicinity of the created hydraulic fracture are recorded and
interpreted to indicate the direction (azimuth) and length and
height of the created fracture.
[0006] However, these known methods are indirect measurement, and
rely on interpretations that may be erroneous, and are difficult to
use for real-time evaluation and optimization of the hydraulic
fracture treatment.
[0007] It is therefore an object of the present invention to
provide a new approach to evaluate the fracture geometry.
SUMMARY OF INVENTION
[0008] According to the present invention, the fracture geometry is
evaluated by placing inside the fracture small devices that, either
actively or passively, give us measurements of the fracture
geometry. Fracture materials (small objects with distinctive
properties e.g. metal beads with very low resistivity) or devices
(e.g. small electronic or acoustic transmitters) are introduced
into the fracture during the fracture treatment with the fracturing
fluid.
[0009] According to a first embodiment of the present invention,
active devices are added into the fracturing fluid. These devices
will actively transmit data that provide information on the device
position and thereafter, can be associated with fracture
geometry.
[0010] According to another embodiment of the present invention,
passive devices are added into the fracturing fluid. In the
preferred embodiment, these passive devices are also used as
proppant.
DETAILED DESCRIPTION
[0011] Examples of "active" device include electronic microsensors,
for example such as radio frequency transmitter, or acoustic
transceivers. These "active" devices will be integrated with
location tracking hardware to transmit their position as they flow
with the fracture fluid/slurry inside the created fracture. The
microsensors can be pumped with the hydraulic fracturing fluids
throughout the treatment or during selected strategic stage of the
fracturing treatment (pad, forward portion of the proppant-loaded
fluid, tail portion of the proppant-loaded fluid) to provide direct
indication of the fracture length and height. The microsensors
would form a network using wireless links to neighboring
microsensors and have location and positioning capability through
for example local positioning algorithms.
[0012] Pressure and Temperature sensors could also be integrated
with the above-mentioned active devices. The resulting pressure and
temperature measurements would be used to better calibrate and
advance the modeling techniques for hydraulic fracture propagation.
They would also allow optimization of the fracturing fluids by
indicating the actual conditions under which these fluids are
expected to perform. In addition chemical sensors could also be
integrated to allow monitoring of the fluid performance during the
treatment.
[0013] Since the number of active devices required is small
compared to the number of proppant grains, it is possible to use
devices significantly bigger than the proppant pumped in the
fracturing fluid. The active devices could be added after the
blending unit and slurry pump, for instance through a lateral
by-pass.
[0014] Examples of such device include small wireless sensor
networks that combine microsensor technology, low power distributed
signal processing, and low cost wireless networking capability in a
compact system as disclosed for instance in International Patent
Application WO0126334, preferably using a data-handling protocol
such as TinyOS, so that the devices organize themselves in a
network by listening to one another, therefore allowing
communication from the tip of the fracture to the well and on to
the surface even if the signals are weak so that the signals are
relayed from the farthest devices towards the devices still closest
to the recorder to allow uninterrupted transmission and capture of
data. The sensors may be designed using MEMS technology or the
spherical shaped semiconductor integrated circuit as known form
U.S.
[0015] A recorder placed at surface or, downhole in the wellbore,
could capture and record/transmit the data sent by the devices to a
computer for further processing and analysis. The data could also
be transmitted to offices in any part of the world using the
Internet to allow remote participation in decisions affecting the
hydraulic fracturing treatment outcome.
[0016] Should the frequency range utilized by the electronic
transmitters be such that the borehole metal casing would block its
transmission from the formation behind the casing into the
wellbore, antennas could be deployed across the perforation
tunnels. These antennas could be mounted on non-conductive
spherical or ovoid balls slightly larger than the perforation
diameter and designed to be pumped and to seat in some of the
perforations and relay the signals across the metallic casing wall.
An alternative method of deployment would be for the transmitter to
trail an antenna wire while being pumped.
[0017] A further variant would cover the case where the measuring
devices are optical fibers with a physical link to a recorder at
surface or in the borehole that would be deployed through the
perforations when the well is cased perforated or directly into the
fracture in an open hole situation. The optical fiber would allow
length measurements as well as pressure and temperature.
[0018] An important alternative embodiment of this invention covers
the use of materials with specific properties that would enable
information on the fracture geometry to be obtained using an
additional measurement device.
[0019] Specific examples of "passive" materials include the use of
metallic fibers or beads as proppant. These would replace some or
all of the conventional proppant and may have sufficient
compressive-strength to resist crushing at fracture closure. A tool
to measure resistivity at varying depths of investigation would be
deployed in the borehole of the fractured well. As the proppant is
conductive with a significant contrast in resistivity compared to
the surrounding formations, the resistance measurements would be
interpreted to provide information on fracture geometry.
[0020] Another example is the use of ferrous/magnetic fibers or
beads. These would replace some or all of the conventional proppant
and may have sufficient compressive strength to resist crushing at
fracture closure. A tool containing magnetometers would be deployed
in the borehole of the fractured well. As the proppant generates a
significant contrast in magnetic field compared to the surrounding
formations, the magnetic field measurements would be interpreted to
provide information on fracture geometry. According to a variant of
this example, the measuring tools are deployed on the surface or in
offset wells. More generally, tools such as resistivity tools,
electromagnetic devices, and ultra long arrays of electrodes, can
easily detect this proppant enabling fracture height, fracture
width, and with processing, the propped fracture length to some
extent can be determined.
[0021] A further step is covered whereby the information provided
be the techniques described above would be used to calibrate
parameters in a fracture propagation model to allow more accurate
design and implementation of fractures in nearby wells in
geological formations with similar properties and immediate action
on the design of the fracture being placed to further the economic
outcome.
[0022] For example, if the measurements indicate that the fracture
treatment is confined to only a portion of the formation interval
being treated, real time design tools would validate suggested
actions, e.g. increase rate and viscosity of the fluid or use of
ball sealer to divert the fluid and treat the remainder of the
interval of interest.
[0023] If the measurements indicate that the sought after tip
screenout did not occur yet in a typical Frac and Pack treatment
and that the fracture created is still at a safe distance from a
nearby water zone, the real time design tool would be re-calibrated
and used to validate an extension of the pump schedule. This
extension would incorporate injection of additional proppant laden
slurry to achieve the tip screenout necessary for production
performance, while not breaking through into the water zone.
[0024] The measurements would also indicate the success of special
materials and pumping procedures that are utilized during a
fracture treatment to keep the fracture confined away from a nearby
water or gas zone. This knowledge would allow either proceeding
with the treatment with confidence of its economic success, or
taking additional actions, e.g. re-design or repeat the special
pumping procedure and materials to ensure better success at staying
away from the water zone.
[0025] Among the "passive" materials, metallic particles may be
used. These particles may be added as a "filler" to the proppant or
replaces part of the proppant, In a most preferred embodiment,
metallic particles consisting of an elongated particulate metallic
material, wherein individual particles of said particulate material
have a shape with a lengthaspect ration greater than 5 are used
both as proppant and "passive" materials.
[0026] Advantageously, the use of metallic fibers as proppant
contributes to enhance proppant conductivity and is further
compatible with techniques known to enhance proppant conductivity
such as the use of conductivity enhancing materials (in particular
the use of breakers) and the use of non-damaging fracturing based
fluids such as gelled oils, viscoelastic surfactant based fluids,
foamed fluids and emulsified fluids.
[0027] Where at least part of the proppant consists of metallic In
all embodiments of the disclosed invention, at least part of the
fracturing fluid comprises a proppant essentially consisting
essentially of an elongated particulate metallic material, said
individual particles of said particulate material have a shape with
a lengthaspect ration greater than 5. Though the elongated material
is most commonly a wire segment, other shapes such as ribbon or
fibers having a non-constant diameter may also be used, provided
that the length to equivalent diameter is greater than 5,
preferably greater than 8 and most preferably greater than 10.
According to a preferred embodiment, the individual particles of
said particulate material have a length ranging between about 1 mm
and 25 mm, most preferably ranging between about 2 mm and about 15
mm, most preferably from about 5 mm to about 10 mm. Preferred
diameters (or equivalent diameter where the base is not circular)
typically range between about 0.1 mm and about 1 mm and most
preferably between about 0.2 mm and about 0.5 mm. It must be
understood that depending on the process of manufacturing, small
variations of shapes, lengths and diameters are normally
expected.
[0028] The elongated material is substantially metallic but can
include an organic part for instance such as a resin-coating.
Preferred metal includes iron, ferrite, low carbon steel, stainless
steel and iron-alloys. Depending on the application, and more
particularly of the closure stress expected to be encountered in
the fracture, "soft" alloys may be used though metallic wires
having a hardness between about 45 and about 55 Rockwell C are
usually preferred.
[0029] The wire-proppant of the invention can be used during the
whole propping stage or to only prop part of the fracture. In one
embodiment, the method of propping a fracture in a subterranean
formation comprises two non-simultaneous steps of placing a first
proppant consisting of an essentially spherical particulate
non-metallic material and placing a second proppant consisting
essentially of an elongated material having a length to equivalent
diameter greater than 5. By essentially spherical particulate
non-metallic material it is meant hereby any conventional proppant,
well known from those skilled in the art of fracturing, and
consisting for instance of sand, silica, synthetic organic
particles, glass microspheres, ceramics including
alumino-silicates, sintered bauxite and mixtures thereof or
deformable particulate material as described for instance in U.S.
Pat. No. 6,330,916. In another embodiment, the wire-proppant is
only added to a portion of the fracturing fluid, preferably the
tail portion. In both cases, the wire-proppant of the invention is
not blended with the conventional material and the fracture
proppant material or if blended with, the conventional material
makes up to no more than about 25% by weight of the total fracture
proppant mixture, preferably no more than about 15% by weight.
[0030] Experiemental Methods:
[0031] A test was made to compare proppant made of metallic balls,
made of stainless steel SS 302, having an average diameter of about
1.6 mm and wire proppant manufactured by cutting an uncoated iron
wire of SS 302 stainless steel into segments approximately 7.6 mm
long. The wire was about 1.6 mm diameter.
[0032] The proppant was deposited between two Ohio sandstone slabs
in a fracture conductivity apparatus and subjected to a standard
proppant pack conductivity test. The experiments were done at 100
.degree. F., 2 lb/ft proppant loading and 3 closure stresses, 3000,
6000 and 9000 psi (corresponding to about 20.6, 41.4 and 62 MPa).
The permeability, fracture gap and conductivity results of steel
balls and wires are shown in Table 1.
1 Permeability .multidot. Fracture .multidot. Conductivity losure
.multidot. Str- (darcy) Gap .multidot. (inch) (md-ft)
ess.paragraph. (psi) Ball Wire Ball Wire Ball Wire 3000 3,703
10,335 0.085 0.119 26,232 102,398 6000 1,077 4,126 0.061 0.095
5,472 33,090 9000 705 1,304 0.064 0.076 3,174 8,249
[0033] The conductivity is the product of the permeability (in
milliDarcy) by the fracture gap (in feet).
* * * * *