U.S. patent application number 13/923311 was filed with the patent office on 2014-12-25 for electromagnetic imaging of proppant in induced fractures.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to Pabrita Sen, Michael Wilt.
Application Number | 20140374091 13/923311 |
Document ID | / |
Family ID | 52109952 |
Filed Date | 2014-12-25 |
United States Patent
Application |
20140374091 |
Kind Code |
A1 |
Wilt; Michael ; et
al. |
December 25, 2014 |
Electromagnetic Imaging Of Proppant In Induced Fractures
Abstract
A method may include forming a borehole in a subterranean
formation, lining at least part of the borehole with an
electrically conductive casing, and injecting a fracturing fluid, a
proppant, and a sensing additive into the borehole to form a
propped fracture pattern. The method may further include driving
the electrically conductive casing so that the sensing additive
generates an electromagnetic (EM) field, sensing the EM field, and
mapping the propped fracture pattern based upon the sensed EM
field.
Inventors: |
Wilt; Michael; (Walnut
Creek, CA) ; Sen; Pabrita; (Chapel Hill, NC) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
52109952 |
Appl. No.: |
13/923311 |
Filed: |
June 20, 2013 |
Current U.S.
Class: |
166/254.1 ;
166/66 |
Current CPC
Class: |
E21B 49/00 20130101;
E21B 43/267 20130101 |
Class at
Publication: |
166/254.1 ;
166/66 |
International
Class: |
E21B 49/00 20060101
E21B049/00 |
Claims
1. A method comprising: forming a borehole in a subterranean
formation; lining at least part of the borehole with an
electrically conductive casing; injecting a fracturing fluid, a
proppant, and a sensing additive into the borehole to form a
propped fracture pattern; driving the electrically conductive
casing so that the sensing additive generates an electromagnetic
(EM) field; sensing the EM field; and mapping the propped fracture
pattern based upon the sensed EM field.
2. The method of claim 1 wherein driving comprises driving the
electrically conductive casing with an alternating current
(AC).
3. The method of claim 2 wherein the AC current has a frequency of
less than 100 Hz.
4. The method of claim 2 wherein the AC current has a frequency of
less than 1000 Hz.
5. The method of claim 1 wherein sensing comprises sensing from
within the borehole.
6. The method of claim 1 wherein sensing comprises sensing remote
from the borehole.
7. The method of claim 1 wherein sensing comprises magnetic field
sensing.
8. The method of claim 1 wherein sensing comprises electric field
sensing.
9. The method of claim 1 wherein the sensing additive comprises at
least one of electrically conductive particles, magnetic particles,
and polarizable particles.
10. The method of claim 1 wherein the sensing additive comprises
particles have an elongate shape.
11. The method of claim 1 wherein a proppant to sensing additive
volume ratio is greater than 7 to 1.
12. A method for mapping a propped fracture pattern adjacent a
borehole in a subterranean formation, an electrically conductive
casing lining at least part of the borehole, and the propped
fracture pattern comprising a sensing additive, the method
comprising: driving the electrically conductive casing so that the
sensing additive generates an electromagnetic (EM) field; sensing
the EM field; and mapping the propped fracture pattern based upon
the sensed EM field.
13. The method of claim 12 wherein driving comprises driving the
electrically conductive casing with an alternating current
(AC).
14. The method of claim 12 wherein sensing comprises sensing from
within the borehole.
15. The method of claim 12 wherein sensing comprises sensing remote
from the borehole.
16. An apparatus comprising: an electrically conductive casing
within a borehole of a subterranean formation having a proppant and
a sensing additive within a propped fracture pattern adjacent the
borehole; a signal source to drive the electrically conductive
casing so that the sensing additive generates an electromagnetic
(EM) field; at least one sensor to sense the EM field; and a
mapping device coupled to said at least one sensor to map the
propped fracture pattern based upon the sensed EM field.
17. The apparatus of claim 16 wherein said signal source comprises
an alternating current (AC) source.
18. The apparatus of claim 16 wherein said at least one sensor is
to sense the EM field from within the borehole.
19. The apparatus of claim 16 wherein said at least one sensor is
to sense the EM field remotely from the borehole.
20. The apparatus of claim 16 wherein said at least one sensor
comprises at least one of a magnetic field sensor and an electric
field sensor.
Description
BACKGROUND
[0001] Hydraulic fracturing, which is also known as "fracking", is
a technique used to release a hydrocarbon resource such as oil or
natural gas from a subterranean rock formation. During the fracking
process, a wellbore is drilled through the top surface layers down
to the rock formation where the hydrocarbon resource is located. A
hydraulic fluid is then introduced into the wellbore and pressurize
to create cracks or fractures through the rock formation, through
which the hydrocarbon resource may be extracted through the
wellbore.
[0002] To maintain a desired fracture width and help keep the
fractures open (or slow their rate of closing), a proppant may be
injected into fractures. More particularly, materials such as
grains of sand, ceramics, or other particulates are used as
proppants to help prevent the fractures from closing when the
injection is stopped and the pressure of the fluid is reduced.
Different types of proppants may be selected for different depths,
since at deeper depths the pressure and stresses on fractures are
higher. The propped fractures are sufficiently permeable to allow
the flow of the hydrocarbon resource to the wellbore, as well as
other fluids that may be introduced into the wellbore during the
drilling or fracturing process.
SUMMARY
[0003] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0004] A method is provided herein which may include forming a
borehole in a subterranean formation, lining at least part of the
borehole with an electrically conductive casing, and injecting a
fracturing fluid, a proppant, and a sensing additive into the
borehole to form a propped fracture pattern. The method may further
include driving the electrically conductive casing so that the
sensing additive generates an electromagnetic (EM) field, sensing
the EM field, and mapping the propped fracture pattern based upon
the sensed EM field.
[0005] A related method is for mapping a propped fracture pattern
adjacent a borehole in a subterranean formation, where an
electrically conductive casing lines at least part of the borehole,
and the propped fracture pattern includes a sensing additive. The
method may include driving the electrically conductive casing so
that the sensing additive generates an EM field, sensing the EM
field, and mapping the propped fracture pattern based upon the
sensed EM field.
[0006] A related apparatus may include an electrically conductive
casing within a borehole of a subterranean formation having a
proppant and a sensing additive within a propped fracture pattern
adjacent the borehole. The apparatus may further include a signal
source to drive the electrically conductive casing so that the
sensing additive generates an EM field (e.g., a secondary EM
field), at least one sensor to sense the EM field, and a mapping
device coupled to the at least one sensor to map the propped
fracture pattern based upon the sensed EM field.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] FIG. 1 is a schematic block diagram of an example embodiment
of an apparatus for mapping induced fracture patterns in a
subterranean formation.
[0008] FIG. 2 is a schematic block diagram of another example
embodiment of an apparatus for mapping induced fracture patterns in
a subterranean formation.
[0009] FIG. 3 is a schematic block diagram of still another example
embodiment of an apparatus for mapping induced fracture patterns in
a subterranean formation.
[0010] FIG. 4 is an enlarged view of an example imaging additive
for use with the systems of FIGS. 1-3.
[0011] FIG. 5 is a flow diagram illustrating various fracture
pattern mapping method aspects.
DETAILED DESCRIPTION
[0012] The present description is made with reference to the
accompanying drawings, in which example embodiments are shown.
However, many different embodiments may be used, and thus the
description should not be construed as limited to the embodiments
set forth herein. Rather, these embodiments are provided so that
this disclosure will be thorough and complete. Like numbers refer
to like elements throughout, and prime and multiple prime notation
are used to indicate similar elements in different embodiments.
[0013] Referring initially to FIGS. 1 and 5, an apparatus 30 for
imaging an induced fracture pattern in a subterranean formation 31
and related method aspects are first described. A wellbore 35
extends into the subterranean formation 31, which illustratively
includes one or more upper layers 32 (e.g., topsoil, aquifer layer,
etc.) and a reservoir layer(s) 33 (e.g., a rock or limestone layer,
etc.) where a hydrocarbon resource is located.
[0014] By way of background, induced fractures 34 are being used
for developing oil and gas fields in the US and abroad. These
fractures 34 provide pathways for fluids (e.g., oil, natural gas,
etc.) to flow from the reservoir layers 33 into a wellbore 35 that
is drilled into the subterranean formation 31. The fractures 34
enhance fluid flow in tight, low permeability formations. However,
the geometry and characteristics of induced fractures 34 are not
always well understood. Of interest to field operators is the
determination of what part of the fractured volume has been forced
to remain open by an injected proppant 36 within the fractures 34.
A "propped" fracture 34 is considered to represent the portion of
the fractured volume that is connecting the reservoir and the
wellbore 35.
[0015] Generally speaking, the apparatus 30 and related method
aspects described herein allow for improving the detectability of a
propped segment of induced fractures 34 using co-injected contrast
or imaging agents or additives, and electromagnetic (EM) methods to
image these fractures. The approach involves injecting conductive,
dielectric and/or magnetic contrast agents (also referred to as a
sensing additive herein) along with proppants such as sand and/or
ceramic materials. These contrast agents may be introduced as a
mixture with regular proppants, the proppants may be modified to
incorporate contrast agents, or a mixture of both may be used. The
sensing additive may have similar sizes as the proppant particles
so that there is relatively little loss of the proppant/contrast
material into the formation. Subsequently, the location and
distribution of the sensing additive may be illuminated and
interrogated by single well or multi-well EM approaches, as will be
discussed further below.
[0016] More particularly, with reference to the flow diagram 50 of
FIG. 5, beginning at Block 51 the borehole 35 is formed (e.g.,
drilled) in the subterranean formation 31, at Block 52, and at
least part of the borehole is lined with an electrically conductive
casing 37, at Block 53. The conductive casing 37 may serve several
purposes, such as support during drilling, allowing flowback
returns during drilling and cementing of the surface casing, and to
help prevent collapse of loose soil near the surface, for example.
Typical sizes for a conductive casing may be from about 18 to 30
inches, although other sizes may be used as well. By way of
example, the conductive casing 37 may comprise steel, etc.
[0017] After a fracturing fluid is injected into the borehole 35 to
induce the fractures 34, a proppant is injected into the borehole
to form a propped fracture pattern, at Block 54. The fracturing
fluid and proppant may be injected through holes in the casing 37,
for example. More particularly, the casing 37 allows the interval
in the borehole 35 to be pressure-isolated, and perforations in the
casing in the interval of interest allow the fracking fluid and
proppant to be introduced at that location. As noted above, the
proppant (and/or the fracturing fluid) includes a sensing additive.
As a result, the electrically conductive casing 37 may be driven by
a signal source 38 so that the sensing additive generates an
electromagnetic (EM) field, at Block 55. That is, the casing 37
essentially provides an antenna to illuminate the sensing additive
within the fractures 34. The EM field generated by the sensing
additive may be considered as a total EM field resulting from the
primary field from the signal source 38 as well as the secondary
field from the target (i.e., sensing additive).
[0018] In the illustrated example, the signal source 38 is coupled
to the casing 37 within the wellbore 35 adjacent to the area where
the fractures 34 are located. The signal source 38 is also coupled
to an electrode 39, which is positioned in the subterranean
formation 31 and spaced apart from the borehole 35. However, other
suitable electrode configurations or placements may be used when
driving the casing 37.
[0019] In the example illustrated in FIG. 1, one or more EM sensors
40 are positioned in the borehole 35 adjacent the fractures 34 to
be imaged. The EM sensor 40 is configured to sense an EM field from
the sensing additive when driven by the signal source 38 via the
casing 37, at Block 56. Example measuring units which may be
configured to provide EM sensing through the casing 37 are
described in U.S. Pat. No. 4,796,186 to Kaufman and U.S. Pat. No.
4,820,989 to Vail, III, which are hereby incorporated herein in
their entireties by reference.
[0020] The system 30 further illustratively includes a mapping
device 41 coupled to the EM sensor 40, which collects the EM field
data from the EM sensor and maps the propped fracture pattern based
upon the sensed EM field, at Block 57, which concludes the method
illustrated in FIG. 5 (Block 58). By way of example, the mapping
device 41 may be implemented using hardware (e.g., processor,
memory, etc.) and associated computer-executable instructions. It
should be noted that some or all of the mapping device components
may be located remotely from the well site. That is, the data may
be collected at the well site for mapping using a mapping device 41
located offsite.
[0021] In other example embodiments, EM sensors may be located
remote from the borehole 35. In another example embodiment
illustrated in FIG. 2, one or more EM sensor devices 40' may be
positioned at the surface of the subterranean formation 31',
instead of (or in addition to) within the borehole 35'. In still
another example embodiment shown in FIG. 3, the EM sensor(s) 40''
may be positioned in one or more separate boreholes 45'' spaced
apart from the primary borehole 35'', although an EM sensor may
also be positioned within the primary borehole as well. The
separate borehole(s) 45'' need not necessarily be lined with a
casing.
[0022] With respect to the sensing additive, a relatively small
volume fraction of a highly conductive material in the fracture
fluid and/or proppant 36 can make the effective conductivity of the
fractured regions 34 filled by this proppant relatively high.
Generally speaking, the electrical properties of the proppant
mixtures are determined by the concentration, shape and
distribution of constituents. There is a percolation type behavior
when highly conducting material is distributed in a relatively
poorly conducting host. That is, the overall conductivity remains
low until the highly conducting phase forms a well-connected
"percolating" path for conduction.
[0023] In the case of a subterranean formation 31, the "host" may
be the fracture fluid and inert portion part of the proppant, and
the highly conducting part may be metallic particles such as
aluminum or graphite beads, a conducting polymer, or a conductive
material coating on sand/ceramic that can be mixed with the sand.
The percolation threshold (f.sub.c) volume fraction depends on the
aspect ratio. For spherical grains, theoretical models give f.sub.c
to be about 0.28, that is, a relatively large volume fraction of
conducting phase is needed. However, this percolating volume
fraction may be reduced by using different geometries, such as an
elongate or needle-like conductive phase particles 50, as shown in
FIG. 4. That is, a relatively small volume fraction of
needle-shaped conductive particles 50 may form a spanning or a
percolating path through the propped fractures 34. By way of
example, such non-spherical sensing co-agents may be included in
the proppant mix to enhance the proppant conductivity or
polarization at modest concentration levels of less than 15% by
volume, and more particularly about 10-15%. Stated alternatively, a
proppant to sensing additive volume ration may be greater than
about 7 to 1. Example sensing agents may include aluminum, pyrite,
magnetite, or graphite, and may be chosen based upon compatibility
with chemistry of the fracture fluids. As noted above, inert
proppants (e.g., sand, ceramic, etc.) may be coated with conductive
or magnetic agents using doped polymers or resins.
[0024] By way of example, proppant sensing additives may be
illuminated by various electromagnetic mechanisms. First, if the
sensing additive changes the magnetic susceptibility of the propped
zone, it can be illuminated with a low frequency magnetic signal
(e.g., 20 Hz or less) that couples into the proppant through an
enhancement of the magnetic field. Another approach is that
electrically conductive sensing additives may be illuminated using
a relatively low frequency electrical signal (e.g., 100 Hz or
less), or a higher frequency electrical or magnetic source (e.g.,
1000 Hz or less). At low frequency, the electrical signals are
directly affected, via Ohm-s law, due to the change in electrical
conductivity of the propped fracture 34. At higher frequencies, the
electrical or magnetic signals couple electromagnetically into the
proppant 36, causing secondary currents to flow and these currents,
in turn, produce secondary EM fields. This affect is analogous to a
transformer coupling.
[0025] Another approach is that conductive sensing additives may
also be detected from their polarization effect. More particularly,
if the conductors in the proppant are disseminated, the low
frequency EM field will polarize the isolated conductive regions.
When the external field is removed, the polarized regions will
generate their own relaxation field as they return to
equilibrium.
[0026] Contrast sensing additives which may be used to enhance the
magnetic field include magnetite, illmenite or particles of iron.
Conductivity enhancements may be affected by various metallic
conductors including pyrite, aluminum, graphite, or a stainless
steel coating, etc. Polarizability may be enhanced by discontinuous
metallic conductors.
[0027] Generally speaking, imaging of the collected data may be
accomplished by fitting the measurements to calculations from a
numerical model, typical by an inverse procedure. Here, one may
assume a physical property distribution corresponding to the
background and fracture properties, and then adjust the model until
the measured and calculated data fits within a tolerance. The final
model depends on the assumptions made, as well as the data and
misfit achieved.
[0028] One imaging model that may be used is a 3D pixelized model.
With this model, the formation is divided into pixels within which
the physical properties (electrical conductivity or magnetic
permeability) are constant. It may be assumed that an initial
property distribution is consistent with an extension of the
borehole logs, and/or other available data, and adjust the
properties of the pixels until a data fit is achieved.
[0029] It should be noted that a rectangular pixelized model may
provide a relatively poor representation of a fractured medium, but
an "effective medium theory" may be used to give an average
physical property distribution within a pixel equivalent to the
fracture properties. Within each pixel, the effective medium theory
will provide the property values and anisotropy to provide an
equivalent response to a fractured medium. The final model does not
necessarily correspond to a fracture distribution, but it will
provide equivalent EM responses to the fracture model. More
particularly, the results of this process will provide property
distribution, property anisotropy and overall dimensions of the
anomalous propped region from a pixelized inversion.
[0030] Numerical codes which may be used in this approach may be
found in Zaslaysky et al., "Hybrid finite-difference integral
equation solver for 3D frequency domain anisotropic electromagnetic
problems," Geophysics 76, 123-137 (2011); and Li et al., "A
compressed implicit Jacobian scheme for 3D electromagnetic data
inversion," Geophysics 76, 173-183 (2011), for example, which are
hereby incorporated herein in their entireties by reference.
Effective medium theory calculations are provided in Choy,
"Effective Medium Theory: Principles and Applications,"
International Series of Monographs on Physics, 1999, for example,
which is also incorporated herein in its entirety by reference.
[0031] Another imaging model that may be used is a sheet model. In
this approach, it may be assumed that the fractured volume may be
approximated by a collection of conductive or magnetized sheets.
The orientation, dimensions and number and properties of sheets are
determined through an inverse or statistical method. Further
details on this approach may be found in Weidelt, "The harmonic and
transient electromagnetic response of a thin dipping dike,"
Geophysics 48, 934-952 (1983), which is hereby incorporated herein
in its entirety by reference.
[0032] Many modifications and other embodiments will come to the
mind of one skilled in the art having the benefit of the teachings
presented in the foregoing descriptions and the associated
drawings. Therefore, it is understood that various modifications
and embodiments are intended to be included within the scope of the
appended claims.
* * * * *