U.S. patent application number 13/829710 was filed with the patent office on 2014-09-18 for method to perform rapid formation fluid analysis.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to DAN EUGENE ANGELESCU, JEFFREY CRANK, MARTIN E. POITZSCH, ROBERT J. SCHROEDER, RONALD E.G. VAN HAL.
Application Number | 20140260586 13/829710 |
Document ID | / |
Family ID | 51521246 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140260586 |
Kind Code |
A1 |
VAN HAL; RONALD E.G. ; et
al. |
September 18, 2014 |
METHOD TO PERFORM RAPID FORMATION FLUID ANALYSIS
Abstract
A method for determining a property of a formation is described
herein. The method includes positioning a wellbore tool at a
location within a wellbore. A formation fluid is withdrawn from the
formation using the wellbore tool. The formation fluid is passed
through a flow line within the wellbore tool and a formation fluid
sample is extracted from the flow line. The method further includes
analyzing the formation fluid sample within the wellbore tool to
determine a property of the formation fluid sample. The analysis is
performed by excluding mud filtrate contamination within the flow
line.
Inventors: |
VAN HAL; RONALD E.G.;
(WATERTOWN, MA) ; CRANK; JEFFREY; (WALPOLE,
MA) ; SCHROEDER; ROBERT J.; (NEWTON, CT) ;
POITZSCH; MARTIN E.; (DERRY, NH) ; ANGELESCU; DAN
EUGENE; (NOISY LE GRAND, FR) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
51521246 |
Appl. No.: |
13/829710 |
Filed: |
March 14, 2013 |
Current U.S.
Class: |
73/152.07 ;
73/152.11 |
Current CPC
Class: |
E21B 49/082
20130101 |
Class at
Publication: |
73/152.07 ;
73/152.11 |
International
Class: |
E21B 49/08 20060101
E21B049/08 |
Claims
1. A method for determining a property of a formation, the method
comprising: positioning a tool at a first location within a
wellbore; withdrawing a formation fluid from the formation at the
first location using the tool, wherein the formation fluid passes
through a flow line within the tool; extracting a formation fluid
sample from the flow line; and analyzing the formation fluid sample
within the tool by excluding mud filtrate contamination within the
flow line.
2. The method according to claim 1, wherein analyzing comprises:
removing water from the formation fluid sample by passing the
formation fluid sample through a membrane when the mud filtrate is
a water-based mud filtrate.
3. The method according to claim 2, wherein the analysis of the
formation fluid sample is selected from the group consisting of:
gas chromatography, mass spectroscopy, visible absorption
spectroscopy, infrared absorption spectroscopy, fluorescence
detection, resistivity measurements, pressure measurements, density
measurements, viscosity measurements, temperature measurements, and
a combination thereof.
4. The method according to claim 1, wherein the analyzing
comprises: analyzing the formation fluid sample using gas
chromatography when the mud filtrate is an oil-based mud
filtrate.
5. The method according to claim 4, wherein analyzing comprises:
identifying a plurality chemical components within the formation
fluid sample; excluding chemical components that comprise the
oil-based mud filtrate; and determining the property of the
formation fluid sample.
6. The method according to claim 5, wherein at least one chemical
component with a carbon number between 8 and 20 is excluded from
consideration.
7. The method according to claim 5, further comprising: using a
known chemical composition of the mud filtrate to exclude chemical
components that comprise the oil-based mud filtrate.
8. The method according to claim 1, further comprising: using the
property of the formation fluid sample to determine whether to
perform an analysis of an uncontaminated formation fluid within the
flow line.
9. The method according to claim 8, wherein the analysis of the
uncontaminated formation fluid comprises: withdrawing the formation
fluid from the formation and pumping the formation fluid through
the flow line until the formation fluid within the flow line is
uncontaminated by mud filtrate; and performing an analysis of the
uncontaminated formation fluid within the tool.
10. The method according to claim 8, wherein the analysis of the
uncontaminated formation fluid comprises: withdrawing the formation
fluid from the formation and pumping the formation fluid through
the flow line until the formation fluid within the flow line is
uncontaminated by mud filtrate; and extracting an uncontaminated
formation fluid sample from the flow line; transporting the
uncontaminated formation fluid sample for surface analysis.
11. The method according to claim 1, further comprising: comparing
the property of the formation fluid sample at the first location to
a property of a second formation fluid sample at a second location
within the wellbore; and using the comparison to determine whether
to perform an analysis of an uncontaminated formation fluid at the
first location.
12. The method according to claim 1, further comprising: comparing
the property of the formation fluid sample at the first location
within the wellbore to a property of a second formation fluid
sample at a second location; and using the comparison to determine
a property of the formation.
13. The method according to claim 12, wherein the second location
is a location selected from the group consisting of: a location
within the wellbore, a location within a second wellbore of a
second well and a location within a second wellbore within a
multilateral well.
14. The method according to claim 1, wherein the property of the
formation fluid sample is a chemical composition for the formation
fluid sample and analyzing the formation fluid sample comprises
determining the chemical composition for the formation fluid
sample.
15. The method according to claim 1, wherein the property of the
formation fluid sample is selected from the group consisting of:
bubble point, dew point, asphaltene onset pressure, density,
viscosity, pressure, temperature, and a combination thereof.
16. The method according to claim 1, wherein the property of the
formation fluid sample is used to determine the property of the
formation.
17. The method according to claim 16, wherein the property of the
formation is selected from the group consisting of: connectivity,
water washing, biodegradation and a combination thereof.
18. A method for determining a property of a formation, the method
comprising: positioning a tool at a location within a wellbore;
withdrawing a formation fluid from the formation at the location
using the tool, wherein the formation fluid passes through a flow
line within the tool; extracting a formation fluid sample from the
flow line; removing water from the formation fluid sample using a
membrane; and analyzing the formation fluid sample within the
wellbore tool to determine a property of the formation fluid
sample.
19. The method of claim 18, wherein the property of the formation
fluid sample is a chemical composition for the formation fluid
sample and analyzing the formation fluid sample comprises
determining the chemical composition for the formation fluid
sample.
20. A method for determining a property of a formation, the method
comprising: positioning a wellbore tool at a location within a
wellbore; withdrawing a formation fluid from the formation at the
location using the wellbore tool, wherein the formation fluid
passes through a flow line within the wellbore tool; extracting a
formation fluid sample from the flow line; identifying a plurality
of chemical components within the formation fluid sample using gas
chromatography; excluding chemical components that comprise an
oil-based mud filtrate; and determining the property of the
formation fluid sample.
Description
TECHNICAL FIELD
[0001] This disclosure relates to fluid analysis, and more
particularly to formation fluid analysis.
BACKGROUND
[0002] Wireline logging is used in the oil and gas field industry
to investigate and determine properties of hydrocarbon reservoir
formations. A wireline logging operation begins by lowering a
wireline tool into a wellbore that traverses a formation. The
wireline tool includes a probe for extracting formation fluid from
the formation and pumping the formation fluid into the wireline
tool. In one example, this formation fluid is then optically
analyzed to determine a chemical composition for the fluid. This
data provides valuable information about the hydrocarbon reservoir
formation that can be used later in completing and producing the
well.
[0003] The optical analysis is performed using a "clean" formation
fluid, which may take a great deal of time to obtain due to mud
filtrate contamination within the formation. The mud filtrate
contamination comes from drilling mud within the wellbore. The
drilling mud can be oil-based or water-based. In many cases, the
drilling mud penetrates a distance into the wellbore and
contaminates the formation fluid. This mud filtrate contamination
can invalidate an optical analysis. For example, oil-based mud
filtrate within the sample can cause inflated values of lumped
alkanes with carbon numbers equal to or greater than six (e.g.,
C.sub.6+ fraction). Furthermore, mud filtrate within the sample can
cause optical scattering from mud particulates and emulsions (e.g.,
oil/water mixtures), which can also invalidate an optical
analysis.
[0004] To obtain a clean sample for analysis, the wireline tool
continuously extracts formation fluid from the formation and pumps
the formation fluid through the tool. Eventually, due to the
limited penetration distance of the drilling mud into the
formation, the formation fluid entering the wireline tool will
"clean up" and will no longer contain a substantial amount of mud
filtrate. The analysis can then be performed on this "clean" sample
of formation fluid. The cleanup time may vary between an hour and
24 hours. The total cleanup time is compounded when cleanup is
repeated at multiple sampling locations within the formation. These
extended cleanup times make wireline logging operations time
consuming. In some cases, such as wireline logging operation
performed on offshore rigs, the extended cleanup times make
wireline logging operations prohibitively expensive.
SUMMARY
[0005] 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.
[0006] Illustrative embodiments are directed to a method for
determining a property of a formation. The method includes
positioning a wellbore tool at a location within a wellbore. A
formation fluid is withdrawn from the formation using the wellbore
tool. The formation fluid is passed through a flow line within the
wellbore tool and a formation fluid sample is extracted from the
flow line. The method further includes analyzing the formation
fluid sample within the wellbore tool to determine a property of
the formation fluid sample. The analysis is performed by excluding
mud filtrate contamination within the flow line. Thus, in some
cases, the analysis is performed before the formation fluid within
the flow line has "cleaned up" and while there is still substantial
mud filtrate contamination within the flow line.
[0007] Various embodiments are also directed to another method for
determining a property of a formation contaminated with water-based
mud filtrate. In this method, a wellbore tool is positioned at a
location within a wellbore and a formation fluid is withdrawn from
the formation using the wellbore tool. The formation fluid is
passed through a flow line within the wellbore tool and a formation
fluid sample is extracted from the flow line. Water is removed from
the formation fluid sample using a membrane and the formation fluid
sample is analyzed within the wellbore tool to determine a property
of the formation fluid sample.
[0008] Further illustrative embodiments are also directed to
another method for determining a property of a formation
contaminated with oil-based mud filtrate. The method includes
positioning a wellbore tool at a location within a wellbore and
withdrawing a formation fluid from the formation using the wellbore
tool. The formation fluid is passed through a flow line within the
wellbore tool and a formation fluid sample is extracted from the
flow line. The method also includes identifying a number of
chemical components within the formation fluid sample using gas
chromatography. Chemical components that appear or may appear
within the oil-based mud filtrate are excluded from consideration.
A remaining set of chemical components from the number of chemical
components is used to determine a property of the formation fluid
sample.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] Those skilled in the art should more fully appreciate
advantages of various embodiments of the present disclosure from
the following "Description of Illustrative Embodiments," discussed
with reference to the drawings summarized immediately below.
[0010] FIG. 1 shows a wireline logging system at a well site in
accordance with one embodiment of the present disclosure;
[0011] FIG. 2 shows a wireline tool in accordance with one
embodiment of the present disclosure;
[0012] FIG. 3A shows a fluid analyzer module in accordance with one
embodiment of the present disclosure;
[0013] FIG. 3B shows a fluid analyzer module in accordance with
another embodiment of the present disclosure;
[0014] FIG. 4 shows a method for determining a property of a
formation in accordance with one embodiment of the present
disclosure;
[0015] FIG. 5 shows a method for determining a property of a
formation contaminated with an oil-based mud filtrate in accordance
with one embodiment of the present disclosure;
[0016] FIG. 6A shows (i) a reference chromatogram that was obtained
by analyzing a formation fluid sample and (ii) a contaminated
chromatogram that was obtained by analyzing the same formation
fluid sample contaminated with an oil-based mud filtrate in
accordance with one embodiment of the present disclosure;
[0017] FIG. 6B shows a more detailed view of the chromatograms of
FIG. 6A.
[0018] FIG. 7 shows a method for determining a property of a
formation that is contaminated by a water-based mud filtrate in
accordance with one embodiment of the present disclosure;
[0019] FIG. 8 shows a plot that was generated by optically
analyzing a formation fluid sample that was separated using a
membrane in accordance with one embodiment of the present
disclosure;
[0020] FIG. 9 shows an original oil sample, an emulsion of the
original oil sample and water, and a sample after the emulsion has
been passed through a membrane in accordance with one embodiment of
the present disclosure;
[0021] FIG. 10 shows a wireline log that was obtained using a rapid
formation fluid analysis method in accordance with one embodiment
of the present disclosure;
[0022] FIG. 11 shows a concurrent wireline log that was obtained
using a conventional fluid analysis system;
[0023] FIG. 12 shows a plot that was obtained using a rapid
formation fluid analysis method in accordance with one embodiment
of the present disclosure;
[0024] FIG. 13 shows optical spectra for a set of single phase
fluids; and
[0025] FIG. 14 shows one potential spectrum generated from a 50
percent oil and water mixture.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0026] Illustrative embodiments of the disclosure are directed to a
method for determining a property of a formation. The method
includes positioning a wellbore tool at a location within a
wellbore. The tool withdraws the formation fluid from the formation
at the location. The formation fluid passes through a flow line
within the wellbore tool and a formation fluid sample is extracted
from the flow line. The method further includes performing an
analysis of the formation fluid sample within the wellbore tool by
excluding mud filtrate contamination within the flow line. In
contrast to past methods, the analysis can be performed before mud
filtrate contamination within the flow line has cleaned up. In this
manner, embodiments described herein perform a "rapid" formation
fluid analysis and avoid extended clean up times and increase
efficiency of wireline logging, logging-while-drilling (LWD), and
other operations. Details of various embodiments are discussed
below.
[0027] FIG. 1 shows one example of a wireline logging system 100 at
a well site. Such a wireline logging system 100 can be used to
implement a rapid formation fluid analysis. In this example, a
wireline tool 102 is lowered into a wellbore 104 that traverses a
formation 106 using a cable 108 and a winch 110. The wireline tool
102 is lowered down into the wellbore 104 and makes a number of
measurements of the adjacent formation 106 at a plurality of
sampling locations along the wellbore 104. The data from these
measurements is communicated through the cable 108 to surface
equipment 112, which may include a processing system for storing
and processing the data obtained by the wireline tool 102. The
surface equipment 112 includes a truck that supports the wireline
tool 102. In other embodiments, the surface equipment may be
located in other locations, such as within a cabin on an off-shore
platform.
[0028] FIG. 2 shows a more detailed view of the wireline tool 102.
The wireline tool includes 102 a selectively extendable fluid
admitting assembly (e.g., probe) 202. This assembly 202 extends
into the formation 106 and withdraws formation fluid from the
formation 116 (e.g., samples the formation). The fluid flows
through the assembly 202 and into a main flow line 204 within a
housing 206 of the tool 102. A pump module 207 is used to withdraw
the formation fluid from the formation 106 and pass the fluid
through the flow line 204. The wireline tool 102 may include a
selectively extendable tool anchoring member 208 that is arranged
to press the probe 202 assembly against the formation 106.
[0029] The wireline tool 102 also includes a fluid analyzer module
210 for analyzing at least a portion of the fluid in the flow line
204. This fluid analyzer module 210 is further described below.
After the fluid analysis module 210, the formation fluid may be
pumped out of the flow line 204 and into the wellbore 104 through a
port 212. Some of the formation fluid may also be passed to a fluid
collection module 214 that includes chambers for collecting fluid
samples and retaining samples of the formation fluid for subsequent
transport and testing at the surface (e.g., at a testing facility
or laboratory).
[0030] FIG. 3A shows a more detailed view of a fluid analyzer
module 210. As shown in FIG. 3A, the fluid analyzer module 210
includes a secondary flow line 302 (e.g., a channel) that is
coupled through a valve 304 to the main flow line 204. The valve
304 selectively passes a sample of formation fluid into the
secondary flow line 302. The secondary flow line 302 also includes
a membrane 306 to separate water from the formation fluid sample
(e.g., a hydrophobic membrane). Such a membrane is described in
U.S. Pat. No. 7,575,681 issued on Aug. 18, 2009 and U.S. Pat. No.
8,262,909 issued on Sep. 11, 2012. Each of these references is
hereby incorporated by reference in their entireties.
[0031] In some embodiments, a pump or a piston (not shown) can be
used to extract the formation fluid sample from the main flow line
204 and pass the formation fluid through the membrane 306. In
various embodiments, the membrane 306 separates water from the
formation fluid sample as the sample is being extracted from the
main flow line 304. Also, in some embodiments, the membrane 306 is
disposed before the valve 304. Once the formation fluid sample
passes the membrane 306, the sample flows into a fluid analyzer 308
that analyzes the sample to determine at least one property of the
fluid sample. The fluid analyzer 308 is in electronic communication
with the surface equipment 112 through, for example, a telemetry
module (not shown) and the cable 108. Accordingly, the data
produced by the fluid analyzer 308 can be communicated to the
surface for further processing by processing system.
[0032] The fluid analyzer 308 can include a number of different
devices and systems that analyze the formation fluid sample. For
example, in one embodiment, the fluid analyzer 308 includes a
spectrometer that uses light to determine a composition of the
formation fluid sample. The spectrometer can determine an
individual fraction of methane (C.sub.1), an individual fraction of
ethane (C.sub.2), a lumped fraction of alkanes with carbon numbers
of three, four, and five (C.sub.3-C.sub.5), and a lumped fraction
of alkanes with a carbon number equal to or greater than six
(C.sub.6+). An example of such a spectrometer is described in U.S.
Pat. No. 4,994,671 issued on Feb. 19, 1991 and U.S. Patent
Application Publication No. 2010/0265492 published on Oct. 21,
2012. Each of these references is hereby incorporated by reference,
in their entireties, herein. In another embodiment, the fluid
analyzer 308 includes a gas chromatograph that determines a
composition of the formation fluid. In one embodiment, the gas
chromatograph determines an individual fraction for each alkane
within a range of carbon numbers from one to 25 (C.sub.1-C.sub.25).
Examples of such gas chromatographs are described in U.S. Pat. No.
8,028,562 issued on Oct. 4, 2011 and U.S. Pat. No. 7,384,453 issued
on Jun. 10, 2008. Each of these references is hereby incorporated
by reference, in their entireties, herein. The fluid analyzer 308
may also include a mass spectrometer, a visible absorption
spectrometer, an infrared absorption spectrometer, a fluorescence
spectrometer, a resistivity sensor, a pressure sensor, a
temperature sensor, a densitometer and/or a viscometer. The fluid
analyzer 308 may also include combinations of such devices and
systems. For example, the fluid analyzer module 210 may include a
spectrometer followed by a gas chromatograph as described in, for
example, U.S. Pat. No. 7,637,151 issued on Dec. 29, 2009 and U.S.
patent application Ser. No. 13/249,535 filed on Sep. 30, 2011. Each
of these references is hereby incorporated by reference, in their
entireties, herein.
[0033] FIG. 3B shows a fluid analyzer module 210 in accordance with
another embodiment of the present disclosure. In this embodiment, a
bypass flow line 301 is coupled to the main flow line 204 through a
first valve 305. The first valve 305 selectively passes formation
fluid from the main flow line 204 into the bypass flow line 301. A
secondary flow line 307 (e.g., a channel) is coupled through a
second valve 309 (e.g., an entrance valve) to the bypass flow line
301. The second valve 309 selectively passes a sample of formation
fluid into the secondary flow line 307. The fluid analyzer module
204 includes a membrane 311 to separate water from the formation
fluid sample (e.g., a hydrophobic membrane). In this embodiment,
the membrane 311 is disposed before the second valve 309. The fluid
analyzer module 210 also includes a third valve 313 (e.g., an exit
valve) between the secondary flow line 307 and the bypass flow line
301. The second valve 309 and the third valve 313 can be used to
isolate the formation fluid sample within the secondary flow line
307. After analysis, the formation fluid sample can pass to the
bypass flow line 301 through the third valve 313.
[0034] In this specific embodiment, the fluid analyzer module 210
further includes a spectrometer 315 followed by a densitometer 317
and a viscometer 319. Such an arrangement will provide both a
chemical composition for the fluid sample and also physical
characteristics for the fluid sample (e.g., density and viscosity).
As explained above, other combinations of devices and systems that
analyze the formation fluid sample are also possible.
[0035] In FIG. 3B, the fluid analyzer module 210 also includes a
pressure unit 321 for changing the pressure within the fluid sample
and a pressure sensor 323 that monitors the pressure of the fluid
sample within the secondary flow channel 307. In one specific
embodiment, the pressure unit 321 is a piston that is in
communication with the secondary flow line 307 and that expands the
volume of the fluid sample to decrease the pressure of the sample.
As explained above, the second valve 309 and the third valve 313
can be used to isolate the formation fluid sample within the
secondary flow line 307. Also, in some embodiments, the pressure
unit 321 can be used to extract the formation fluid sample from the
bypass flow line 301 by changing the pressure within the secondary
flow line 307. The pressure sensor 323 is used to monitor the
pressure of the fluid sample within the secondary flow line 307.
The pressure sensor 323 can be a strain gauge or a resonating
pressure gauge. By changing the pressure of the fluid sample, the
fluid analyzer module 210 can make measurements related to phase
transitions of the fluid sample (e.g., bubble point or asphaltene
onset pressure measurements). Further details of devices and
systems that analyze the formation fluid sample are also provided
in U.S. Provisional Patent Application Ser. No. 61/______ entitled
"Pressure Volume Temperature System" and filed on Mar. 14, 2013
(Attorney Docket No. IS13.3119-US-PSP), which is hereby
incorporated by reference, in its entirety, herein.
[0036] FIG. 4 shows a method 400 for determining a property of a
formation in accordance with one embodiment of the present
disclosure. As shown at process 402, the method 400 includes
positioning a wellbore tool at a first location within a wellbore.
In some embodiments, this wellbore tool is the wireline tool 102,
as shown in FIG. 2. However, in various other embodiments, the
wellbore tool can also be a logging-while-drilling tool. Once
positioned adjacent to a location-of-interest within the formation,
at process 404, the wellbore tool withdraws the formation fluid
from the formation (e.g., samples the formation). The wellbore tool
can use a selectively extendable fluid admitting assembly 202, as
shown in FIG. 2, to withdraw the formation fluid from the
formation. The formation fluid then passes through a main flow line
within the wellbore tool. In some embodiments, the formation fluid
is pumped through the main flow line using the pump module 207. At
process 406, a formation fluid sample is extracted from the main
flow line. In one example, as shown in FIG. 3, the valve 304 is
open between the main flow line 204 and the secondary flow line 302
so that a formation fluid sample passes into the secondary flow
line of the fluid analyzer module 210. In other embodiments, the
formation fluid sample is extracted from a different flow line,
such as bypass flow line 301. At process 408, an analysis of the
formation fluid sample is performed within the wellbore tool to
determine a property of the formation fluid sample. This analysis
is performed by, for example, the fluid analyzer module 210, as
shown in FIGS. 2 and 3.
[0037] At process 408, the analysis of the formation fluid is
performed by excluding the mud filtrate contamination within the
flow line (e.g., the main flow line 204). As explained above, when
the wellbore tool withdraws formation fluid from the formation, the
fluid initially includes mud filtrate contamination. Reference
number 216 within FIG. 2 shows mud filtrate contamination within
the formation 106. According to past methods, the wellbore tool
continues to withdraw and pump formation fluid out of the formation
until the fluid within the main flow line has "cleaned up." One
measure for determining whether the formation fluid has cleaned up
is the stability of the ratio of formation water to oil within the
flow line. After the formation fluid has cleaned up, the clean
formation fluid can be analyzed. Thus, in the past, the approach to
formation fluid analysis was dependent on clean formation fluid
within the flow line. In contrast, the rapid formation fluid
analysis method described herein performs an analysis of the
formation fluid independent of mud filtrate contamination within
the flow line by excluding the mud filtrate contamination within
the flow line. The analysis can be performed before the formation
fluid within the main flow line has "cleaned up" and while there is
still substantial mud filtrate contamination. Substantial mud
filtrate contamination can range between 5 percent and 99 percent
of the fluid within the main flow line. Accordingly, embodiments of
the rapid formation fluid analysis method avoid long cleanup times
and reduce costs associated with wireline and LWD logging
operations, Various embodiments also facilitate wireline and LWD
logging measurements that would otherwise be prohibitively
expensive or pose an excessive risk for "sticking" the wellbore
logging system against the wellbore wall.
[0038] The rapid formation fluid analysis method can be applied to
formations that are contaminated by oil-based drilling muds or
water-based drilling muds. For example, FIG. 5 shows a method 500
for determining a property of a formation that is contaminated by
an oil-based mud filtrate. The method 500 of FIG. 5 includes
positioning a wellbore tool at a first location within a wellbore
502, withdrawing a formation fluid from the formation and passing
the formation fluid through a flow line within the tool 504, and
extracting a formation fluid sample from the flow line 506. The
method 500 further includes identifying a plurality of chemical
components within the formation fluid sample using gas
chromatography 508. In this embodiment, the fluid analyzer module
includes a gas chromatograph that determines the chemical
composition of the fluid sample. In one particular embodiment, the
chromatograph determines the individual chemical components of the
fluid sample from C.sub.1 to C.sub.25. At process 510, chemical
components that constitute the oil-based mud filtrate are excluded
from consideration. In one specific example, one or more chemical
components with carbon numbers between C.sub.8 and C.sub.20 are
excluded from consideration. At process 512, the remaining set of
chemical components (e.g., C.sub.1-C.sub.7 and C.sub.21+) is used
to determine the property of the formation. In this manner, the
method analyzes the formation fluid sample independently of
oil-based mud filtrate contamination within the flow line. Those
chemical components that make up the mud filtrate are not used in
the analysis and thus do not invalidate or adversely impact the
analysis.
[0039] As explained above, chemical components can be excluded from
consideration based upon the composition of the oil-based drilling
mud. In some cases, the chemical composition of the drilling mud is
known and those specific chemical components that constitute the
oil-based drilling mud are excluded from consideration. To this
end, the chemical composition of certain types of drilling muds can
be obtained from a database that includes various types of drilling
muds and their chemical components. Also, the drilling mud can be
analyzed at a surface location using gas chromatography to
determine its chemical components. In one example, C.sub.13 and
C.sub.15-C.sub.18 are known chemical components of the drilling mud
and those chemical components are excluded from consideration.
[0040] FIG. 6A shows a "contaminated" chromatogram 602 that was
obtained by analyzing a formation fluid sample contaminated with an
oil-based mud filtrate. In this case, the formation fluid sample
included 50 percent contamination with an oil-based mud filtrate.
The oil-based mud filtrate included chemical components with carbon
numbers between C.sub.15 to C.sub.18 and those components are
represented as enlarged peaks within the chromatogram. Per process
510 of FIG. 5, the C.sub.15 to C.sub.18 chemical components and
representative peaks are removed from consideration and not used to
determine the properties of the fluid sample. FIG. 6A also shows a
reference chromatogram 604 that was obtained by analyzing a
formation fluid sample that was uncontaminated by the oil-based mud
filtrate. The enlarged peaks representative of the oil-based mud
filtrate do not appear within the reference chromatogram 604.
[0041] FIG. 6B shows a more detailed view of the chromatograms 602,
604 of FIG. 6A. In particular, FIG. 6B shows the representative
peaks of components with carbon numbers from C.sub.1 to C.sub.7.
The representative peaks within the contaminated chromatogram 602
match the representative peaks within the reference chromatogram
604. The peaks within the contaminated chromatogram 602 are smaller
than the representative peaks within the reference chromatogram 604
due to the smaller quantity of original formation fluid in the
contaminated chromatogram. As explained above, the contaminated
sample included 50 percent contamination from oil-based mud
filtrate. FIGS. 6A and 6B show that the representative peaks from
C.sub.1 to C.sub.7 within the contaminated chromatogram 602 can be
reliably used to determine a property of the formation fluid sample
because they match the representative peaks within the reference
chromatogram 604. More specifically, the representative peaks from
C.sub.1 to C.sub.14 and the representative peaks greater than
C.sub.18 can be used to determine a property of the formation fluid
sample because those areas of the chromatogram were not affected by
the oil-based mud filtrate.
[0042] In some embodiments, when the specific chemical components
of the drilling mud are unknown, a broader range of chemical
components can be excluded from consideration. In one example,
chemical components with carbon numbers between C.sub.8 and
C.sub.20 are excluded because drilling muds generally include
chemical components with carbon numbers between C.sub.8 and
C.sub.20. Oil-based drilling muds are often made from diesel, a
distillation fraction or synthetic oil. Such oil-based muds have a
limited carbon number range. Typically, the lowest carbon number
observed is C.sub.10 or C.sub.11, but some diesel and distillation
based muds will start at C.sub.8 or C.sub.9. Other oil-based muds,
such as synthetic oil-based muds, are much more monodisperse and
have a higher carbon number anywhere from C.sub.12 to C.sub.16. The
highest carbon number in an oil-based drilling mud is more variable
and ranges from C.sub.14, for some lighter muds, to C.sub.29, for
some of the distillate-based muds. Generally, the end point for
carbon numbers is between C.sub.16 and C.sub.20. Accordingly, on
the higher end, there are small concentrations of components above
the C.sub.20 endpoint within drilling muds and, at the lower end,
there are very small concentrations of components below
C.sub.8.
[0043] The method 500 of FIG. 5 will provide a partial chemical
composition of the formation fluid within the formation (e.g.,
individual C.sub.1-C.sub.7 and C.sub.21+ fractions). In turn, this
chemical composition information can be used to determine a
property of the formation (e.g., a hydrocarbon reservoir). In one
example, the partial chemical composition itself is a property of
the formation and provides information about the different types of
hydrocarbons present within the formation. The partial chemical
composition can also be used to determine other properties of the
formation. For example, the lighter individual hydrocarbon
fractions (e.g., C.sub.1-C.sub.7) that remain for consideration can
provide valuable information about the properties of the formation.
Specifically, C.sub.7 isomers are separated using gas
chromatography and the C.sub.7 isomer ratio can be used to
determine the source of the hydrocarbons within the formation, the
maturity of the hydrocarbons, the biodegradation of the
hydrocarbons, the fractionation of the hydrocarbons, the water
washing of the hydrocarbons, and/or thermochemical sulfate
reduction of the hydrocarbons, as described in, for example, Peters
et al., The Biomarker Guide, Vol. 1, pp. 162-190 (2007). In
particular, a decreased ratio of toluene over n-heptane indicates
water washing and proximity of a water zone. An increase of the
cyclopentanes over n-heptane indicates biodegradation. In another
example, the chemical components from C.sub.1 to C.sub.5 can be
used to determine wetness ratios, balance ratios, and character
ratios as described in Haworth et al., Interpretation of
Hydrocarbon Shows Using Light (C.sub.1-C.sub.5) Hydrocarbon Gases
From Mud Log Data, AAPG Vol. 69, pp. 1305-1310 (1985). In yet
another example, the ratios between the C.sub.1, C.sub.2, C.sub.3
and C.sub.4 components (e.g., elevated (C.sub.1) levels in
particular) can be used to determine the presence of secondary
charging or biodegradation.
[0044] The heavier individual fractions (e.g., C.sub.21+) including
biomarkers that remain for consideration can also provide valuable
information about the properties of the formation. For example,
biomarkers can be used to determine properties of the formation.
Biomarkers are complex organic compounds that are disposed in
sediments, rocks, and crude oils and show little or no change in
chemical structure from their original parent organic molecules,
which were part of living organisms. Biomarkers can be used to
determine the history of the oil within the formation. In
particular, biomarkers can be used to identify oil-oil and
oil-source rock correlations and thermal maturity. Ptystane and
phytane are acyclic isoprenoid biomarkers that elute around
C.sub.17 and C.sub.18. Other biomarkers will elute between C.sub.24
and C.sub.36, such as hopanes, which elute around C.sub.27 to
C.sub.29. Further details about how biomarkers can be used to
determine properties of formation are described in Peters et al.,
The Biomarker Guide, Vol. 2, pp. 473-640, 645-703 (2007).
[0045] The rapid formation fluid analysis method can also be
applied to formations that are contaminated by water-based drilling
muds. For example, FIG. 7 shows a method 700 for determining a
property of a formation that is contaminated by a water-based mud
filtrate. The method 700 of FIG. 7 includes positioning a wellbore
tool at a first location within a wellbore 702, withdrawing a
formation fluid from the formation and passing the formation fluid
through a flow line within the wellbore tool 704, and extracting a
formation fluid sample from the flow line 706 (e.g. the main flow
line 204 or bypass flow line 301). At process 708, the method 700
further includes removing water from the formation fluid sample by
passing the formation fluid sample through a membrane. This
membrane may be a hydrophobic membrane that separates a water
fraction from an oil fraction, such as the membrane 306 shown in
FIG. 3. Furthermore, processes 706 and 708 may happen
simultaneously. Then, at process 710, the formation fluid sample is
analyzed within the wellbore tool to determine a property of the
formation. In one example of the method, the fluid analyzer is a
spectrometer and the analyzing process 710 is performed to measure
the C.sub.1, C.sub.2, lumped C.sub.3-C.sub.5, and lumped C.sub.6+
fractions within the formation fluid sample. This analysis is
performed independently of water-based mud filtrate contamination
within the flow line because the membrane removes the water before
the formation fluid sample enters the fluid analyzer. Accordingly,
the method can analyze the formation fluid sample before the water
filtrate within the flow line has cleaned up.
[0046] As explained above, the membrane removes water filtrate from
the formation fluid sample and improves the accuracy of the fluid
analyzer. In various embodiments, the purpose of performing the
fluid analysis on the formation fluid is to determine the chemical
components of the hydrocarbon fraction within the formation fluid
sample (e.g., the C.sub.1, C.sub.2, lumped C.sub.3-C.sub.5, and
lumped C.sub.6+ fractions). The presence of water within the sample
can adversely impact this analysis. For example, when performing an
optical analysis using a spectrometer, the water within the sample
scatters the light signal from the spectrometer and generates
artifacts within the detected light signal. In other systems,
software can be used to remove these artifacts. In some cases,
however, the water fraction and the hydrocarbon fraction can create
an emulsion. Emulsions that appear within the flow line may be
difficult to cleanup even with extended cleanup times and the
artifacts they generate in detected light signals can be very
difficult to remove. In various embodiments, the membrane
advantageously separates the water fraction from the hydrocarbon
fraction. In this manner, the optical analysis can be performed on
a single phase hydrocarbon sample without interference from other
phases (e.g., a water fraction).
[0047] Illustrative embodiments of the rapid formation analysis
method can be used to reliably produce a formation fluid sample
that accurately represents the original hydrocarbon fraction within
the formation. FIG. 8 shows a plot 806 that was generated by
optically analyzing a formation fluid sample that was separated
using the membrane. In particular, three different plots are shown
within FIG. 8. Plot 802 represents the optical spectrum for a heavy
oil and plot 804 shows the optical spectrum produced by an emulsion
of water and the same heavy oil. As the plots show, the water has a
substantial impact on the optical diffraction of the sample and
many optical characteristics of the original crude oil are lost.
Plot 806 shows the optical spectrum produced by the separated heavy
oil. To produce plot 806, the emulsion of water and the heavy oil
was passed through the membrane and then optically analyzed. Plot
806 is nearly identical to the plot 802 produced by the original
heavy oil. FIG. 8 shows that the membrane can be reliably used to
remove the water fraction and to produce a formation fluid sample
that accurately represents the original hydrocarbon fraction within
the formation.
[0048] FIG. 9 shows a series of oils samples. Sample 902 is an
original oil sample, sample 904 is an emulsion of the original oil
sample and water and sample 906 represents a sample after the
emulsion has been passed through the membrane. FIG. 9 shows how a
membrane can be used to return a formation fluid sample to a state
that accurately represents the original hydrocarbon fraction within
the formation.
[0049] Various embodiments of the rapid formation analysis method
can be used to accurately detect and analyze the hydrocarbon
fraction of formation fluids. FIG. 10 shows a wireline log 1000
that was obtained using a rapid formation fluid analysis method. In
particular, the log 1000 in FIG. 10 was obtained using a
spectrometer disposed behind a hydrophobic membrane. FIG. 11 shows
a concurrent wireline log 1100 that was obtained using a
spectrometer-based conventional fluid analysis system. A comparison
between FIGS. 10 and 11 shows the ability of the membrane to
produce a stable optical measurement. The wireline log 1100 in FIG.
11 shows a live plot of oil and water fractions. Reference number
1102 refers to areas with large fluctuations of water and reference
number 1104 refers to areas with large fluctuations in oil. In some
cases, the conventional fluid analysis system yields data where the
oil and water fraction add up to greater than one. This means that
the data in these areas in the log 1100 is generally not reliable.
Reference number 1106 refers to such areas on the wireline log
1100. Such areas 1106 are an indication of very high optical
scattering due to mud filtrate inside the flow line. In contrast,
the wireline log 1000 in FIG. 10 shows a wireline log 1000 that was
obtained using a 4 channel spectrometer disposed behind a
hydrophobic membrane. The wireline log includes plots 1002, 1004,
1006, 1008 for each channel of the spectrometer. As shown by the
plots, even when the conventional system fails to detect oil (e.g.,
around time mark 1071.0 on the wireline log 1100), the 4 channel
spectrometer records a signal that can be used to determine the
composition of the oil. This comparison shows that the combination
of the membrane and spectrometer can detect much smaller optical
oil signatures, as compared to the conventional system. FIG. 10
further shows that the oil signal is stable for the next 1.8 hours,
whereas the conventional system shows heavy fluctuation of oil and
water.
[0050] FIG. 12 shows another example of how the rapid formation
analysis method can be used to accurately detect and analyze the
hydrocarbon fraction of formation fluids. In this example, the
rapid formation fluid analysis method was implemented by a wireline
tool with a selectively extendable fluid admitting assembly (e.g.,
probe). In particular, three different plots are shown within FIG.
12. Plot 1202 represents an optical spectrum generated by a
spectrometer that was located near the probe of the wireline tool
before a pump (e.g., after probe 202 and before pump module 207 in
FIG. 2). The spectrometer before the pump analyzes an initial
formation fluid that is free of a water/oil emulsion. Accordingly,
plot 1202 has a low optical density baseline with no evidence of
optical scattering. The second plot 1204 represents an optical
spectrum generated by a second spectrometer that is disposed
further downstream after the pump within the wireline tool (e.g.,
after pump module 207 in FIG. 2). This second spectrometer produces
a large increase in optical scattering because the pump churns up
oil and water within the formation fluid and produces a highly
scattering emulsion. Plot 1206 represents an optical spectrum
generated by a third spectrometer that was also located after the
pump (e.g., after pump module 207 in FIG. 2). This third
spectrometer, however, was disposed after a hydrophobic membrane
that removed water from the formation fluid sample. As shown by
plot 1206, the rapid formation analysis method accurately
reproduces the optical spectrum 1202 generated by the initial
emulsion-free formation fluid.
[0051] Various embodiments of the rapid formation analysis method
can also be used to accurately determine a fluid color for
hydrocarbon fractions within formation fluids. The fluid color of a
formation fluid is used for fluid typing (e.g., determining the
presence of water, gas, condensate, light oil, medium oil, and/or
heavy oil). In another example, the fluid color is used to quantify
the oil-based mud filtrate contamination within the formation
fluid. Fluid color measurements may be influenced by the presence
of water (e.g., from a water-based mud filtrate). FIG. 13 shows
optical spectra for a set of single phase fluids, such as water,
heavy oil, medium oil, etc. The optical spectrum that results from
a mixture of oil and water depends on (1) the oil and water
fraction and (2) how the fluids mix together. FIG. 14 shows one
potential spectrum generated from a 50 percent oil and water
mixture. The mixture had a multi-phase flow with slugs of oil and
slugs of water (e.g., a "sluggy" flow). As compared with FIG. 13,
the oil color is affected dramatically by the presence of water. In
particular, the methane absorption peak (C.sub.1) is quite weak and
can be masked in the presence of water. By applying the rapid
formation analysis method, the water can be removed from the
formation fluid and a more accurate color of the formation fluid
can be obtained.
[0052] With respect to water-based drilling muds, the rapid
formation fluid analysis method is not limited to any particular
type of fluid analysis technique. Optically analyzing formation
fluid samples using a spectrometer is one example. In other
embodiments, gas chromatography can be used to determine the
individual C.sub.1 to C.sub.25 fractions of the formation fluid
sample. For example, in one specific embodiment, the fluid analyzer
module, as shown in FIG. 3, includes a gas chromatograph. This
fluid analyzer configuration can be used to analyze formation fluid
contaminated with both water-based mud filtrates and oil-based mud
filtrates. When analyzing a formation fluid with water based
contamination, the hydrophobic membrane removes the water from the
formation fluid and the gas chromatograph analyzes the formation
fluid sample to determine the individual C.sub.1 to C.sub.25
fractions within the formation fluid sample. In the case when the
mud filtrate is an oil-based mud filtrate, the gas chromatograph
analyzes the formation fluid sample to determine the individual
C.sub.1 to C.sub.25 fractions within the formation fluid sample and
the chemical components that constitute the oil-based mud filtrate
are excluded from consideration. In this case, although the
hydrophobic membrane does not prevent oil-based mud filtrate from
passing to the gas chromatograph, the membrane does advantageously
protect the gas chromatograph from water, which can damage
stationary phases within the gas chromatograph. In yet further
embodiments, one of mass spectroscopy, visible absorption
spectroscopy, infrared absorption spectroscopy, fluorescence
detection, bubble point measurements, dew point measurements,
asphaltene onset pressure measurements, resistivity measurements,
fluid pressure measurements, fluid density measurements, fluid
viscosity measurements, and fluid temperature measurements can also
be used to analyze the formation fluid sample. Combinations of such
techniques may also be used.
[0053] The rapid formation analysis method can be implemented a
number of different ways in order to increase the efficiency of
logging operations and provide valuable information about the
formation. In one example, a wireline tool performs a rapid
formation fluid analysis at a plurality of sampling locations
within the wellbore. In so doing, the logging operation avoids
cleanup time at each sampling location, while also providing
valuable information about the formation at each location. More
specifically, the rapid formation analysis provides a partial
chemical composition of the formation fluid at each of the sampling
locations. Such a partial chemical composition indicates the
presence of different types of hydrocarbons within the formation
and shows how those types of hydrocarbons change between the
different sampling locations. In one example, the C.sub.1, C.sub.2,
lumped C.sub.3-C.sub.5, and lumped C.sub.6+ fractions from an
optical analysis can be used for fluid typing and determining
connectivity within the formation. In another example, the lighter
individual hydrocarbon fractions (e.g., C.sub.1-C.sub.7) from a gas
chromatography analysis can be used to determine the source of the
hydrocarbons within the formation, the maturity of the
hydrocarbons, the biodegradation of the hydrocarbons, the
fractionation of the hydrocarbons, the water washing of the
hydrocarbons, and thermochemical sulfate reduction of the
hydrocarbons.
[0054] In various embodiments, the partial chemical compositions at
each of the sampling locations are compared against each other to
determine other properties of the formation, such as connectivity
within the formation. By using ratios of certain chemical
components at the sampling locations, a comparison can be made
between different sampling locations to determine whether the
sampling locations are connected. For example, the ratio between
heptane and methylcyclohexane can be used to determine
connectivity. In another specific example, a ratio between heptane
and a total amount of dimethylcyclopentanes (or an individual
amount of a dimethylcyclopentane) can be used to determine
connectivity. Sampling locations with similar chemical compositions
are likely connected. Such comparisons can be made (1) between one
or more sampling locations within the same wellbore, (2) between
one or more sampling locations within different wellbores of the
same multilateral well, and (3) between one or more sampling
locations within different wells.
[0055] In some embodiments, the rapid formation analysis method can
be used to determine whether to perform a more comprehensive
analysis of the formation at a sampling location. In such
embodiments, the wireline tool performs a comprehensive analysis of
the formation at a first sampling location. In one example, the
comprehensive analysis includes analyzing an uncontaminated fluid
sample. To this end, the wellbore tool withdraws the formation
fluid from the formation and pumps the formation fluid through the
flow line until the formation fluid within the flow line is
uncontaminated by mud filtrate. In one specific example, the flow
line is the main flow line represented by reference number 204 in
FIG. 2. Once the formation fluid is uncontaminated, the analysis of
the formation fluid is performed. The analysis of the
uncontaminated formation fluid can be performed within the main
flow line or the uncontaminated formation fluid can be extracted
from the main flow line into a secondary flow line and analyzed
within the secondary channel. In another example, the comprehensive
analysis includes extracting an uncontaminated formation fluid
sample from the flow line and then transporting the uncontaminated
formation fluid sample for surface analysis.
[0056] The more comprehensive analysis of the formation fluid at
the first sampling location can provide additional information,
such as a water fraction for the formation fluid or more complete
chemical composition identification (e.g., a complete set of
individual fractions for C.sub.1 to C.sub.25). As explained above,
however, the disadvantage of this more comprehensive analysis is
the additional clean up time. The rapid formation analysis method
can be applied at the next sampling location to increase the
efficiency of the logging operation. For example, the wellbore tool
is moved to a second sampling location and the rapid formation
analysis method is performed to determine a partial chemical
composition of the formation fluid. By comparing the partial
chemical composition at the second sampling location to the more
complete chemical composition at the first sampling location, the
connectivity between the sampling locations can be determined. If
there is no connectivity between the two sampling locations, then a
more comprehensive analysis at the second sampling location can be
performed (e.g., an analysis of an uncontaminated formation fluid).
If there is connectivity between the two sampling locations, then a
determination that the two sampling locations have similar
formation properties can be made and the wellbore tool does not
perform a more comprehensive analysis at the second sampling
location. Instead, the wellbore tool moves on to analyze the
formation at a third sampling location. This process can be
repeated iteratively. In this manner, the rapid formation analysis
method can be used to avoid acquisition of redundant data at
multiple sampling locations, which, in turn, also increases logging
efficiency.
[0057] Illustrative embodiments of the present disclosure are not
limited to wireline logging operations, such as the ones shown in
FIGS. 1-3. For example, the embodiments described herein can also
be used with any suitable means of conveyance, such coiled tubing.
Furthermore, various embodiments of the present disclosure may also
be applied in logging-while-drilling (LWD) operations,
sampling-while-drilling operations, measuring-while-drilling
operations or any other operation where sampling of the formation
is performed.
[0058] Some of the processes described herein, such as (1)
determining a property of the formation fluid sample, (2)
determining a property of a formation, (3) excluding chemical
components that constitute oil-based mud filtrate, (4) using a set
of remaining chemical components to determine a property of a
formation fluid sample, (5) determining whether to perform an
analysis of an uncontaminated formation fluid using a property of a
formation fluid sample, and (6) comparing a property of a formation
fluid sample at a first location to a property of a second
formation fluid sample at a second location, can be performed by a
processing system.
[0059] In one specific embodiment, the processing system is located
at the well site as part of the surface equipment (e.g., the truck
112 in FIG. 1). The processes are performed at the well site using
the processing system within the truck. In other embodiments,
however, the processes may be performed at a location that is
remote from the well site, such as an office building or a
laboratory.
[0060] The term "processing system" should not be construed to
limit the embodiments disclosed herein to any particular device
type or system. In one embodiment, the processing system includes a
computer system. The computer system may be a laptop computer, a
desktop computer, or a mainframe computer. The computer system may
include a graphical user interface (GUI) so that a user can
interact with the computer system. The computer system may also
include a computer processor (e.g., a microprocessor,
microcontroller, digital signal processor, or general purpose
computer) for executing any of the methods and processes described
above (e.g. processes (1)-(6)).
[0061] The computer system may further include a memory such as a
semiconductor memory device (e.g., a RAM, ROM, PROM, EEPROM, or
Flash-Programmable RAM), a magnetic memory device (e.g., a diskette
or fixed disk), an optical memory device (e.g., a CD-ROM), a PC
card (e.g., PCMCIA card), or other memory device. This memory may
be used to store, for example, data from the wellbore tool.
[0062] Some of the methods and processes described above, including
processes (1)-(6), as listed above, can be implemented as computer
program logic for use with the computer processor. The computer
program logic may be embodied in various forms, including a source
code form or a computer executable form. Source code may include a
series of computer program instructions in a variety of programming
languages (e.g., an object code, an assembly language or a
high-level language such as C, C++ or JAVA). Such computer
instructions can be stored in a non-transitory computer readable
medium (e.g., memory) and executed by the computer processor. The
computer instructions may be distributed in any form as a removable
storage medium with accompanying printed or electronic
documentation (e.g., shrink wrapped software), preloaded with a
computer system (e.g., on system ROM or fixed disk), or distributed
from a server or electronic bulletin board over a communication
system (e.g., the Internet or World Wide Web).
[0063] Additionally, the processing system may include discrete
electronic components coupled to a printed circuit board,
integrated circuitry (e.g., Application Specific Integrated
Circuits (ASIC)), and/or programmable logic devices (e.g., a Field
Programmable Gate Arrays (FPGA)). Any of the methods and processes
described above can be implemented using such logic devices.
[0064] Although several example embodiments have been described in
detail above, those skilled in the art will readily appreciate that
many modifications are possible in the example embodiments without
materially departing from the scope of this disclosure.
Accordingly, all such modifications are intended to be included
within the scope of this disclosure.
* * * * *