U.S. patent application number 13/131872 was filed with the patent office on 2012-05-31 for fracture characterization using directional electromagnetic resistivity measurements.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Michael S. Bittar, Clive D. Menezes.
Application Number | 20120133367 13/131872 |
Document ID | / |
Family ID | 43607247 |
Filed Date | 2012-05-31 |
United States Patent
Application |
20120133367 |
Kind Code |
A1 |
Bittar; Michael S. ; et
al. |
May 31, 2012 |
Fracture Characterization Using Directional Electromagnetic
Resistivity Measurements
Abstract
A disclosed fracture characterization method includes:
collecting three-dimensional resistivity measurements of a volume
surrounding an open borehole; analyzing the measurements to
determine parameters describing fractures in the volume; and
providing a report to a user based at least in part on said
parameters. A fluid with a contrasting resistivity is employed to
make the fractures detectable by a directional electromagnetic
logging tool in the borehole. illustrative parameters include
fracture direction, height, extent, length, and thickness. The
resistivity measurements can be augmented using a borehole wall
image logging tool. Also disclosed are fracturing methods that
include: positioning a directional electromagnetic logging tool
proximate to a formation; fracturing the formation; monitoring
fracture progression with said tool; and halting the fracturing
when measurements by said tool indicate that a predetermined set of
criteria have been satisfied.
Inventors: |
Bittar; Michael S.;
(Houston, TX) ; Menezes; Clive D.; (Conroe,
TX) |
Assignee: |
Halliburton Energy Services,
Inc.
Houston
TX
|
Family ID: |
43607247 |
Appl. No.: |
13/131872 |
Filed: |
August 20, 2009 |
PCT Filed: |
August 20, 2009 |
PCT NO: |
PCT/US09/54470 |
371 Date: |
May 30, 2011 |
Current U.S.
Class: |
324/346 |
Current CPC
Class: |
G01V 3/18 20130101; E21B
49/00 20130101; G01V 3/20 20130101; E21B 47/13 20200501; E21B 43/26
20130101 |
Class at
Publication: |
324/346 |
International
Class: |
G01V 3/17 20060101
G01V003/17 |
Claims
1. A fracture characterization method that comprises: collecting
three-dimensional measurements of a volume surrounding an open
borehole, wherein the volume includes at least one fracture filled
with a fluid having a resistivity that contrasts with the
formation; analyzing the measurements to determine at least one
parameter describing said fracture; and providing a report to a
user based at least in part on said parameter.
2. The method of claim 1, wherein the at least one parameter
comprises a fracture direction.
3. The method of claim 1, wherein the at least one parameter
comprises at least one dimension in the set consisting of a
fracture height, a fracture extent, a fracture length, and a
fracture thickness.
4. The method of claim 1, further comprising injecting said fluid
into the borehole before collecting said measurements.
5. The method of claim 1, further comprising collecting a borehole
wall image log to measure characteristics of said fracture where it
intersects the borehole.
6. The method of claim 6, wherein the three-dimensional
measurements are acquired by a directional electromagnetic
resistivity tool, and the borehole wall image log is acquired by an
acoustic tool or a micro-resistivity tool.
7. A logging assembly that comprises: an electromagnetic
resistivity tool that acquires resistivity measurements as a
function of position, orientation, and radial distance; a borehole
wall image logging tool that acquires borehole wall measurements as
a function of position and orientation; and an uphole or downhole
processor that combines said resistivity and borehole wall
measurements to detect fractures and create a log of at least one
fracture parameter.
8. The logging assembly of claim 7, wherein the at least one
fracture parameter includes a parameter from the set comprising
fracture direction, fracture height, fracture extent, fracture
length, and fracture thickness.
9. The logging assembly of claim 7, further comprising a processing
system that displays said log to a user.
10. A fracturing method that comprises: positioning a directional
electromagnetic logging tool proximate to a formation; fracturing
the formation; monitoring fracture progression with said tool; and
halting the fracturing when measurements by said tool indicate that
a predetermined set of criteria have been satisfied.
11. The method of claim 10, wherein said monitoring includes:
collecting three-dimensional measurements of the formation with
said tool while fracturing; deriving at least one fracture
dimension from said measurements; and determining whether the at
least one fracture dimension satisfies the set of criteria.
12. The method of claim 10, wherein the set of criteria includes a
minimum length subject to a maximum extent.
13. The method of claim 10, wherein said fracturing includes
injecting a fracturing fluid having a resistivity less than 10% of
the formation's resistivity.
14. The method of claim 10, wherein said fracturing includes
injecting a fracturing fluid having a conductivity less than 10% of
the formation's conductivity.
15. The method of claim 10, further comprising: obtaining a
borehole wall image log; and combining information from the
borehole wall image log with said measurements to determine at
least one fracture dimension.
16. A fracturing assembly that comprises; a fluid injection port
that supplies a fluid into a borehole in a formation; a directional
electromagnetic logging tool positioned to obtain three-dimensional
measurements of the formation exposed to the fluid; and a processor
that determines fracturing progress from said measurements and
communicates said progress to an operator.
17. The fracturing assembly of claim 16, wherein the port jets the
fluid against the borehole wall, and wherein the port is located
between antennas of the directional electromagnetic logging
tool.
18. The fracturing assembly of claim 16, wherein the directional
electromagnetic tool is a wireline tool suspended through the fluid
injection port.
19. The fracturing assembly of claim 16, further comprising a
borehole wall imaging tool.
20. The fracturing assembly of claim 16, wherein the processor
extracts at least one fracture dimension from said measurements,
wherein the at least one fracture dimension is in a set consisting
of fracture direction, fracture height, fracture extent, fracture
length, and fracture thickness.
Description
BACKGROUND
[0001] As drillers create wells to extract fluids from subterranean
formations, they often perform a "fracturing" operation in which a
fluid is injected into the well bore under high pressure to enlarge
any existing fractures in the formation and to create new
fractures. The injected fluid often carries entrained particulate
matter to be deposited in the fractures, thereby propping them open
when the pressure returns to normal. Such fractures substantially
increase the permeability of the formation--making it easier for
fluid to flow from the formation into the well bore (and vice
versa). Fracturing operations are also often employed in injection
wells, i.e., wells created to inject fluids into subterranean
formations for disposal, storage, or reservoir flooding.
[0002] In any case, it is often desirable to confine the effects of
the fracturing operation to a bounded region. For example, any
fractures that would promote fluid flow between formations are
generally undesirable, as such flows can contaminate water tables,
relieve reservoir pressures, divert fluids into inaccessible
regions, or create other problems. Accordingly, oilfield operators
employ models to predict the effects of a fracturing operation and,
in some cases, employ micro-seismic detection to monitor fracture
evolution during the fracturing operation itself. The seismic
sensors are typically positioned in one or more monitoring wells
spaced apart from the fracturing well, but in at least one proposed
method the seismic sensors are positioned in a concrete annulus
around the bore of the injecting well. See, e.g., U.S. Pat. No.
5,503,252 to Withers, titled "System and Method for Monitoring the
Location of Fractures in Earth Formations". Such seismic monitoring
methods often perform inadequately in regions having high seismic
attenuation or significant seismic interference.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] A better understanding of the various disclosed embodiments
can be obtained when the detailed description is considered in
conjunction with the accompanying drawings, in which:
[0004] FIG. 1 shows an illustrative fracturing while drilling
environment;
[0005] FIG. 2 shows a second illustrative fracturing
environment;
[0006] FIG. 3 shows some illustrative fracture characteristics;
[0007] FIG. 4 shows an illustrative 3D volume;
[0008] FIG. 5 shows an illustrative borehole wall image;
[0009] FIG. 6 shows an illustrative software architecture;
[0010] FIG. 7 shows an illustrative fracture characterization
method; and
[0011] FIG. 8 shows an illustrative extended fracture monitoring
array.
[0012] While the invention is susceptible to various modifications
and alternative forms, specific embodiments thereof are shown by
way of example in the drawings and will herein be described in
detail. It should be understood, however, that the drawings and
detailed description thereto are not intended to limit the claims
to the particular forms described herein, but on the contrary, the
intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the patented
claims.
DETAILED DESCRIPTION
[0013] The problems identified in the background are at least
partly addressed by a borehole assembly that provides fracture
characterization and monitoring of fracture progression. In some
method embodiments, a fracturing fluid with a contrasting
resistivity is employed to make the formation fractures detectable
by a directional electromagnetic logging tool in the borehole. A
directional electromagnetic logging tool collects three-dimensional
measurements of a volume surrounding an open borehole. Such
measurements can be collected during or after a fracturing
operation. In some cases these 3D measurements will be augmented by
borehole wall image measurements that complement the deep
directional resistivity measurements. In any case, the measurements
are analyzed to determine parameters characterizing fractures in
the formation and to report these parameters to a user.
Illustrative parameters include fracture direction, height, extent,
length, and thickness. The resistivity measurements can be
augmented using a borehole wall image logging tool.
[0014] Also disclosed are certain tool assemblies. Some disclosed
logging assemblies include an electromagnetic resistivity tool, a
borehole wall imaging tool, and a processor. The electromagnetic
resistivity tool acquires resistivity measurements as a function of
position, orientation, and radial distance. The borehole wall image
logging tool acquires borehole wall measurements as a function of
position and orientation. The processor combines said resistivity
and borehole wail measurements to detect fractures and create a log
of at least one fracture parameter, which can be displayed to a
user.
[0015] Some disclosed fracturing assemblies include: a fluid
injection port, a directional electromagnetic logging tool, and a
processor. The fluid injection port supplies a fluid into a
borehole to fracture a formation. The directional electromagnetic
logging tool is positioned to obtain three-dimensional measurements
of the formation being fractured. The processor determines
fracturing progress from said measurements and communicates said
progress to an operator.
[0016] Turning now to the figures, FIG. 1 shows an illustrative
fracturing while drilling environment. A platform 2 supports a
derrick 4 having a traveling block 6 that raises and lowers a drill
string 8 in a borehole 20. A top drive 10 rotates the drill string
8 as the string is lowered through the wellhead, thereby driving a
drill bit 14 to create and extend the borehole 20. A pump 16
circulates fluid through a feed pipe 18 to the drill string 8. The
fluid flows down through the interior of the string 8 to the bit
14, passes through one or more orifices to remove drill cuttings
from the hole bottom, and move upward along the annulus around the
string 8 to carry the cuttings from the hole 20 into a pit 22.
[0017] The bit 14 is part of a bottom hole assembly, or "BHA", that
includes drill collars to add weight and rigidity to the end of the
drill string 8. The thick walls of the drill collars make them a
convenient location for downhole tools and instrumentation. The
bottomhole assembly of FIG. 1 includes a borehole wall imager 24, a
directional electromagnetic logging tool 26, a stimulation tool 28,
and a telemetry tool 30, The telemetry tool 30 includes a BHA
control module and a position/orientation sensing module. Other
downhole tools can be included in the BHA, as well as normal
(non-instrumented) drill collars.
[0018] The borehole wall imager 24 measures one or more properties
of the borehole wall as a function of tool position and
orientation, thereby enabling the BHA to log an image of the
borehole wall. Many suitable imaging technologies exist. In certain
embodiments, the borehole wall imager employs acoustic transducers
that rotate with the drill string to measure the acoustic
impedance, acoustic reflectance, or the density of the formation at
its interface with the borehole, In other embodiments, the borehole
wall imager employs micro-resistivity measurements of the borehole
wall. In yet other embodiments, gamma-ray or neutron attenuation
measurements are collected. Each of these technologies provides the
ability to identify locations where faults and voids intersect the
borehole, and they can enable analysis of rock textures to
determine formation composition and stress directions--information
which can be instrumental for determining where and how to initiate
a fracturing process. Illustrative examples of potentially suitable
tools are disclosed in U.S. Pat. No. 4,829,488 ("Drive Mechanism
for Borehole Televiewer"), U.S. Pat. No. 5,899,958 ("Logging while
drilling borehole imaging . . . , "), U.S. Pat. No. 6,191,588
("Methods and Apparatus for Imaging Earth Formation . . . "), and
U.S. Pat. No. 6,359,438 ("Multi-depth focused resistivity imaging
tool . . . ".
[0019] The directional electromagnetic logging tool 26 collects
measurements indicative of the formation resistivity, permittivity,
or other related properties (e.g., attenuation, phase shift,
velocity) as a function of depth, azimuth, and radial distance from
the borehole, Some tool designs employ tilted coil antennas that
rotate with the drill string to make azimuthally sensitive
measurements, and radial sensitivity can be achieved with multiple
transmit-receive antenna spacings and/or multiple signal
frequencies. Other tool designs employ antenna triads that can be
"virtually" steered independently of the physical tool. Yet other
designs employ downhole radar transducers for transmitting pulses
and measuring reflections.
[0020] Each of these technologies offers the ability to identify
regions having contrasting resistivities in the formation around
the borehole. Illustrative examples of potentially suitable tools
are disclosed in U.S. Pat. No. 5,757,191 ("Virtual Induction Sonde
for Steering Transmitted and Received Signals"), U.S. Pat. No.
6,181,138 ("Directional Resistivity Measurements for Azimuthal
Proximity Detection . . . "), U.S. Pat. No. 6,476,609
("Electromagnetic Wave Resistivity Tool Having a Tilted Antenna . .
. "), and co-pending application ______ ("A 3D Borehole Imager").
Each of these and other BHA tools can be powered by downhole
batteries and/or downhole power generators such as a turbine in the
fluid flow stream.
[0021] The stimulation tool 28 includes one or more ports for
injecting a fracturing fluid into a formation. In some embodiments,
such as those disclosed in U.S. Pat. App. Pub, 2005/0230107
("Methods of Well Stimulation During Drilling Operations"), the
ports are designed to jet high pressure flow streams directly
against the borehole wall. In other embodiments, the stimulation
tool restricts fluid flow along the borehole away from the ports,
enabling the driller to create a region of high pressure against
the borehole wall. Flow restrictors or packers can be deployed for
this purpose. The intended result of the tool's operation is the
formation and enlargement of fractures 32 in the formation
proximate the stimulation tool. Further discussion of fracturing
while drilling operations can be found in U.S. Pat, App. Pub.
2005/0230107, titled "Methods of Well Stimulation During Drilling
Operations" by inventors Billy McDaniel and Jim Surjaatmadja.
[0022] We note that in FIG. 1, the antennas of the directional
electromagnetic logging tool 26 are positioned above and below the
region of the borehole exposed to the maximum pressure from the
ports of the stimulation tool 28. This tool configuration is chosen
to maximize the sensitivity of tool 26 to the evolution of
fractures 32 during the fracturing process. Nevertheless, at least
some directional electromagnetic logging tool configurations can
sense beyond the end of the tool, so this configuration is not
considered essential,
[0023] Telemetry tool 30 collects the measurements of the other BHA
tools and stores or transmits representative data. The data can be
processed downhole and/or sent to the surface to have the
processing performed there, At the surface, a data acquisition
module 38 collects the telemetry data and conveys it to a data
processing system 50, In the system of FIG. 1, telemetry tool 30
communicates with the surface using mud pulse telemetry, an
established technology that generates pressure waves that propagate
in the fluid flowing through drill string 8, Data acquisition
module 38 detects these waves using sensors 34, 36. A pulsation
dampener 40 can be employed to reduce noise interference caused by
the pump 16. Alternative telemetry technologies exist and can be
used, including electromagnetic telemetry, wired drill pipe
telemetry, and acoustic telemetry along the wall of the drill
string. The various telemetry technologies also permit commands and
configuration information to be communicated to the bottomhole
assembly from the surface, thereby enabling a driller to interact
with the bottomhole assembly and, among other things, steer the
borehole along a desired path in response to data collected by the
BHA.
[0024] Data processing system 50 includes internal data storage and
memory having software (represented by removable information
storage media 52), along with one or more processor cores that
execute the software. The software configures the system to
interact with a user via one or more input/output devices (such as
keyboard 54 and display 56), Among other things, system 50
processes data received from acquisition module 38 and generates a
representative display for the driller to perceive. During a
fracturing operation, the system can display data indicative of
measured fracture parameters and show how they compare to a desired
target, thereby enabling an operator to tailor fluid flow
parameters to optimize the result. In addition to acquiring data
during the fracturing operation, the BHA can be raised and lowered
to perform logging runs through the region of interest before and
after the fracturing operation.
[0025] FIG. 2 shows a second illustrative fracturing environment.
Unlike the fracturing while drilling environment of FIG. 1, FIG. 2
shows that the BHA has been pulled from the borehole. A tubing
string 60 is set in the borehole with one or more packers 62 to
confine the fracturing pressure to the desired region of the
borehole. A tool assembly 64 is suspended by a wireline 66 from a
logging truck 68, In addition to physical support, the wireline
provides a bundle of electrical conductors (and optionally optical
fibers) to provide power from the surface and convey telemetry from
the tool assembly to the processing systems at the surface. The
illustrated tool assembly includes an array of borehole wall
imaging pads 70 and a directional electromagnetic logging tool
72.
[0026] The tool assembly can be conveyed on logging trips through
the open borehole before and after a fracturing operation to
collect three-dimensional measurements of the formation's
electromagnetic properties, as well as images of the borehole
walls. Moreover, the tool assembly can be anchored (or optionally
tripped on logging runs) during the fracturing operation to monitor
the evolution of the fractures. Processing systems in the logging
truck enable operators to observe representative characteristics of
the detected fractures.
[0027] FIG. 3 shows some illustrative fracture characteristics that
can be determined by the processing systems based on measurements
by the directional electromagnetic tool and optionally the borehole
wall imaging tool. In the overhead view of the borehole, FIG. 3
shows a fracture of length L, average thickness T, and azimuthal
angle .alpha. intersecting the borehole. (As used herein, the
azimuthal angle of a fracture represents the fracture's orientation
in the horizontal plane rather than its position relative to the
borehole.) In the side view, it can be seen that the fracture has
an average height H and it intersects the borehole along an extent
X. Such parameters are illustrative of fracture characteristics
that would be of interest to analysts. However, they do not
represent an exhaustive set of parameters nor do they represent a
necessary set of parameters. For example, some analysts may be more
interested in fracture volume, while others may simply need the
limits of a "bounding box" that encloses all the detected
fractures.
[0028] FIG. 4 shows an illustrative 3D volume representing the data
that can be collected by the directional electromagnetic logging
tool. The tool makes formation measurements as a function of depth
(or position along the borehole axis) Z, azimuth angle .alpha., and
radial distance R. This coordinate system is divided into a grid of
cells or "voxels", and the tool determines one or more formation
property measurements for each cell.
[0029] In at least some embodiments, the tool provides resistivity
measurements for 32 or more depths at 256 or more azimuthal angles,
with a depth resolution of 2 centimeters or better, In high
resistivity formations, an operator can use a low resistivity
fracturing fluid such as a saline mud. The directional
electromagnetic logging tool can detect regions of such contrast
material, thereby enabling a processing system to identify
fractures and determine their characteristic parameters, Similarly,
in low resistivity formations, an operator can use a high
resistivity fracturing fluid such as an oil-based mud. If a region
is repeatedly scanned during a fracturing operation, the processing
system can track the evolution of fractures.
[0030] FIG. 5 shows an illustrative borehole wall image 502. An
imaging tool scans the borehole wall and makes formation property
measurements as a function of depth Z and azimuthal angle. As with
the 3D volume, this 2D map is divided into cells or "pixels", and
the tool determines one or more formation property measurements for
each cell, The measurement value can be shown as a color or
intensity value in the map, thereby creating an image of the
borehole wall. Acoustic measurements and micro-resistivity
measurements offer the opportunity for very high resolution images,
with 512 or more azimuthal angles and a depth resolution of 0.5 cm
or better. Such images make bedding structures 504 and faults 506
clearly visible. The processing system 50 can combine such
measurements to obtain a better determination of the fracture
parameters.
[0031] FIG. 6 shows functional block diagrams for an illustrative
software package 602 suitable for running on data processing system
50, optionally in cooperation with other computer systems on a
computer network.
[0032] In block 604, the software determines a model of the
formation. This model can be based on seismic survey data,
augmented by well logs. The model generally includes estimates of
formation bed geometry, formation composition, density, and stress.
In block 606, the software predicts the behavior of the formation
when the formation is subjected to a fracturing process. The
software can rely on rock mechanic models and empirical models from
previous fracturing studies when simulating the evolution of faults
in response to specified fracturing fluid pressures and flow rates.
Once an operator has tried various simulations and arrived at
desirable results, the fracturing operation can begin.
[0033] In block 608, the software configures the processing system
to obtain injection data, i.e., data regarding characteristics of
the fracturing fluid (including resistivity), the borehole
geometry, the fluid flow rate, the fluid pressure, and the
cumulative fluid volume. The software further configures the
processing system to collect 4D resistivity data, i.e., a time
progression of 3D resistivity data. In block 609, the software
optionally obtains a log of the borehole wall image.
[0034] In block 610, the software processes the resistivity data
and optionally combines it with wall image data to extract fault
parameters. Illustrative parameters include fracture azimuth,
fracture complexity, fracture coverage (e.g., the percentage of the
borehole that is within a specified distance of at least one
fracture), fracture height, and fracture half-length. (A fracturing
operation generally forms many fractures. The lengths of these
fractures have an exponential distribution that is characterized in
terms of the half-length, i.e., the length greater than the lengths
of half of the fractures and less than the lengths of the other
half.)
[0035] The extracted fault parameters can be compared to the model
predictions in block 612 to test the model validity and/or
determine if the goals of the fracturing process have been
achieved. This comparison can also he used as the basis for
refining the model or adjusting the injection parameters to
optimize the fracturing process. In the current embodiment, such
refinements and adjustments are in the purview of the user, but in
certain contemplated embodiments the software includes a module for
automatically controlling the injection parameters in response to
the fault parameter measurements. Illustrative adjustments include
reducing the flow rate as fracture parameters approach the target
state.
[0036] In block 614 the history of extracted fault parameters is
recorded to track the evolution of faults during the fracturing
process, A mapping module 616 generates fault maps based on the
information tracked in blocks 610 and 614, enabling the user to
visually monitor the progression of the fracturing process.
[0037] FIG. 7 shows an illustrative fracture characterization
method. Beginning in block 702, the operator drills a well. In
block 704, the operator prepares for a fracturing operation. Such
preparation may include logging the borehole, preparing a model,
determining a fracturing plan based on simulation, and securing
fracturing fluids and equipment. Also included is positioning the
fluid injection ports at the desired fracturing position and, if
necessary, isolating the fracturing region from the rest of the
borehole. In some configurations the operator might also position a
directional electromagnetic logging tool in the vicinity of the
fracturing region.
[0038] In block 706, the operator pumps the fracturing fluid
through the injection port. As mentioned previously, the fluid
possesses an electrical resistivity that contrasts with the
resistivity of the formation. The operator optionally collects
directional electromagnetic logging measurements during the
fracturing process in block 708. Such measurements enable real-time
tracking of fracture evolution so that the operator can tailor the
injection parameters to optimize results.
[0039] Once the fluid injection is complete (or at least
temporarily halted), the operator collects directional
electromagnetic resistivity measurements in block 710, optionally
augmented with a borehole image log. In block 712, the data
processing system extracts fracture parameters from these
measurements. The operator analyzes the fracture parameters in
block 714 and determines whether additional fracturing is desired.
If so, the method loops back to block 704. Otherwise the operator
completes the well in block 716, typically by cementing a casing in
place and perforating it in those locations where it is desired to
produce or inject fluids.
[0040] The region in which direction& electromagnetic logging
tool measurements can be performed can be extended in either or
both of at least two ways illustrated in FIG. 8. FIG. 8 shows a
well 802 being drilled and fractured using a drill string 8. The
drill string 8 includes multiple directional electromagnetic
logging tools 804 to extend the measurement region along the axis
of the well. The measurement region can be extended away from the
well 802 using one or more offset wells 806, 812, each having one
or more directional electromagnetic logging tools. Offset well 806
has an array of directional electromagnetic logging tools 810 on a
continuous tubing string 808 (e.g., coil tubing or composite
tubing). Offset well 812 has an array of directional
electromagnetic logging tools 816 on a wireline 814. Fractures that
extend into the measurement regions of these additional tools 804,
810, 816, can be tracked in real time. If the leading edge of the
fracture is within the range of multiple tools, the measurements
can be combined to triangulate and track the fractures with greater
accuracy.
[0041] Numerous variations and modifications will become apparent
to those skilled in the art once the above disclosure is fully
appreciated. For example, the directional electromagnetic logging
tool can be located outside the borehole, e.g., in a second
borehole near the borehole being fractured, to monitor fracture
formation from a distance. In another embodiment, the directional
electromagnetic logging measurements are used in conjunction with a
micro-seismic monitoring tool to complement and verify the
operation of each. It is intended that the following claims be
interpreted to embrace all such variations and modifications.
* * * * *