U.S. patent application number 13/269954 was filed with the patent office on 2012-05-24 for monitoring injected nonhydrocarbon and nonaqueous fluids through downhole fluid analysis.
Invention is credited to Neil Bostrom, Francois Dubost, Christopher Harrison, Robert Kleinberg, Oliver C. Mullins, Lalitha Venkataramanan.
Application Number | 20120125602 13/269954 |
Document ID | / |
Family ID | 39496615 |
Filed Date | 2012-05-24 |
United States Patent
Application |
20120125602 |
Kind Code |
A1 |
Dubost; Francois ; et
al. |
May 24, 2012 |
Monitoring Injected Nonhydrocarbon And Nonaqueous Fluids Through
Downhole Fluid Analysis
Abstract
A method of monitoring a nonhydrocarbon and nonaqueous fluid
injected into the earth's subsurface through a first wellbore that
involves positioning a fluid analysis tool within a second wellbore
and determining the presence of the injected nonhydrocarbon and
nonaqueous fluid by making a measurement downhole on the injected
nonhydrocarbon and nonaqueous fluid using the fluid analysis tool.
Also a related method of enhancing hydrocarbon production from a
subsurface area having first and second wellbores that involves
injecting a nonhydrocarbon and nonaqueous fluid into the subsurface
through the first wellbore, positioning a fluid analysis tool
within the second wellbore, and determining the presence of the
injected nonhydrocarbon and nonaqueous fluid by making a
measurement downhole on the injected nonhydrocarbon and nonaqueous
fluid using the fluid analysis tool.
Inventors: |
Dubost; Francois; (Orgeval,
FR) ; Mullins; Oliver C.; (Ridgefield, CT) ;
Venkataramanan; Lalitha; (Lexington, MA) ; Harrison;
Christopher; (Auburndale, MA) ; Bostrom; Neil;
(Cambridge, MA) ; Kleinberg; Robert; (Cambridge,
MA) |
Family ID: |
39496615 |
Appl. No.: |
13/269954 |
Filed: |
October 10, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11753863 |
May 25, 2007 |
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13269954 |
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60809887 |
Jun 1, 2006 |
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Current U.S.
Class: |
166/250.01 ;
166/270.2 |
Current CPC
Class: |
E21B 47/10 20130101;
Y02C 20/40 20200801; Y02C 10/14 20130101; E21B 41/0064
20130101 |
Class at
Publication: |
166/250.01 ;
166/270.2 |
International
Class: |
E21B 47/00 20120101
E21B047/00; E21B 43/22 20060101 E21B043/22 |
Claims
1. A method of enhancing hydrocarbon production from a subsurface
area having first and second wellbores comprising: injecting a
nonhydrocarbon and nonaqueous fluid into the subsurface through
said first wellbore; positioning a fluid analysis tool within said
second wellbore; determining the presence of said injected
nonhydrocarbon and nonaqueous fluid by determining fluid properties
of said injected nonhydrocarbon and nonaqueous fluid using said
fluid analysis tool; and identifying a location within said second
wellbore where fluids with relatively high concentrations of said
injected nonhydrocarbon and nonaqueous fluid are entering said
second wellbore.
2. A method of enhancing hydrocarbon production from a subsurface
area in accordance with claim 1, further comprising performing a
treatment on said second wellbore.
3. A method of enhancing hydrocarbon production from a subsurface
area in accordance with claim 2, wherein said treatment inhibits
fluid from entering said second wellbore at said identified
location and flowing to the surface comprises installing one or
more of a bridge plug, a packer, a casing patch, gel, or cement
within said second wellbore.
4. A method of enhancing hydrocarbon production from a subsurface
area in accordance with claim 2, wherein said treatment enhances
the production of fluid entering the wellbore from areas other than
the identified location.
5. A method of enhancing hydrocarbon production from a subsurface
area in accordance with claim 1, further comprising modifying the
rate at which fluid is being withdrawn from said second
wellbore.
6. A method of monitoring a nonhydrocarbon and nonaqueous fluid
injected into the earth's subsurface through a first wellbore
comprising: positioning a fluid analysis tool within a second
wellbore; determining the presence of said injected nonhydrocarbon
and nonaqueous fluid by determining fluid properties of said
injected nonhydrocarbon and nonaqueous fluid using said fluid
analysis tool; repositioning said fluid analysis tool at a
different location within said second wellbore, determining the
presence of said injected nonhydrocarbon and nonaqueous fluid at
said different location by making a measurement downhole on said
injected nonhydrocarbon and nonaqueous fluid using said fluid
analysis tool, and comparing the measurements made at said
different locations.
7. A method of monitoring a nonhydrocarbon and nonaqueous fluid
injected into the earth's subsurface through a first wellbore
comprising: positioning a fluid analysis tool within a second
wellbore; and determining the presence of said injected
nonhydrocarbon and nonaqueous fluid by making a measurement
downhole comprising determining fluid properties of said injected
nonhydrocarbon and nonaqueous fluid using said fluid analysis tool.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation of U.S. Publication No.
2008-0135237, filed Jun. 12, 2008, which claims the benefit of
provisional patent application 60/809,887, filed Jun. 1, 2006, the
entire contents of both applications are incorporated herein by
reference.
FIELD
[0002] This invention relates to the monitoring of nonhydrocarbon
and nonaqueous fluids that have been injected into the subsurface
of the Earth and, more particularly, to methods for monitoring
nonhydrocarbon and nonaqueous fluids that have been injected into
the subsurface of the Earth through the use of downhole fluid
analysis and/or related techniques, particularly in connection with
enhancing hydrocarbon production from a subsurface area.
BACKGROUND
[0003] In certain hydrocarbon reservoirs, such the giant Cantarell
field in Mexico, nonhydrocarbon and nonaqueous fluids are injected
to enhance hydrocarbon production. In the Cantarell field, one
billion cubic feet of nitrogen are injected daily. A mixture of
carbon dioxide and hydrogen sulfide from The Great Plains Synfuels
Plant in North Dakota, United States is being injected into the
Weyburn field in Saskatchewan, Canada for enhanced oil recovery and
geological carbon dioxide sequestration purposes. These types of
hydrocarbon production techniques are typically referred to as
enhanced or tertiary recovery techniques.
[0004] It is of central concern to understand the disposition of
the injected fluids. Clearly, if the injected fluid bypasses oil
pockets or if the fluid reaches nonequilibrium concentrations in
the hydrocarbons in place, whether gas or oil, then the efficiency
of production enhancement can be greatly compromised. It is also
possible for the injected fluids to escape the intended geologic
reservoir interval and potentially migrate back to the surface.
[0005] Using known techniques it would be possible to acquire
several samples downhole as a function of position in the reservoir
and to perform well site or laboratory analysis of the acquired
samples. With this information, one could hope to track the
trajectory of the injected nonhydrocarbon and nonaqueous fluids.
One significant problem with this approach is that it is difficult
to adequately investigate likely fluid and reservoir complexities
using a reasonable sample acquisition program because downhole
fluid sampling tools can typically acquire a very limited number of
samples, typically less than ten, in a single logging run.
[0006] It is also possible to acquire samples of the produced fluid
at the surface and analyze the concentration of the injected fluid
in the produced fluid, but by the time the fluid reaches the
surface, it is typically difficult or impossible to accurately
determine the fraction of injected fluid in the reservoir fluid as
it enters the borehole or to determine at which location the
injected fluid is entering the borehole.
[0007] Downhole Fluid Analysis (DFA), a suite of logging services
developed by Schlumberger primarily for the open-hole hydrocarbon
exploration well environment, enable the real-time evaluation of
fluid composition while sampling thereby allowing a planned
reservoir sample analysis program to be modified as appropriate to
further evaluate fluid complexities as they are discovered. In a
well, if an entire fluid column is found by prudent DFA station
selection to be effectively homogenous then little further analysis
may be called for. However, if significant fluid complexities are
discovered, then additional DFA station tests can be performed.
That is, if the evaluation program does not require filling (a
necessarily finite number of) sample bottles, then one does not
have to cease a downhole fluid evaluation program simply because
all of the available sample bottles have been filled. Of course, if
corroboration of DFA results is desired, downhole sample
acquisition and analysis can be followed by surface analysis and
used to complement the downhole analysis.
[0008] If the injected fluid for production enhancement is water,
then existing methods of oil-water or gas-water differentiation
could be employed to monitor the progress of injected water through
the reservoir. See, for instance, "Method of analyzing oil and
water flow streams", Hines, Wada, Mullins, Tarvin, and Cramer, U.S.
Pat. No. 5,331,156 (1995). If the injected fluid is hydrocarbon
gas, then standard methods of DFA determination of the gas-oil
ratio could be employed. This type of method is described in
"Method and Apparatus for Downhole Compositional Analysis of
Formation Gases", Mullins and Wu, U.S. Pat. No. 5,859,430 (1999)
and "Method and Apparatus for determining Gas-Oil Ratio in a
Geologic Formation through the use of spectroscopy", Mullins, U.S.
Pat. No. 5,939,717 (1999).
[0009] If methane or separator gas is injected into the reservoir,
methods of performing DFA for hydrocarbon compositional
determination could be employed. In particular, near-infrared
spectroscopy is currently employed to quantify methane, other
hydrocarbon gases, and higher molecular weight hydrocarbons. See,
for instance, "Method and apparatus for determining chemical
composition of reservoir fluids", Fujisawa, Mullins, Van Agthoven,
Rabbito, and Jenet, U.S. Pat. No. 7,095,012 (2006).
[0010] However, if the predominant constituents of the injected
fluid are different from hydrocarbon and water, new methods are
called for to monitor the progression of the injected fluids and/or
to enhance hydrocarbon production from the subsurface in which the
fluids are injected.
SUMMARY
[0011] One aspect of the invention is a method of monitoring a
nonhydrocarbon and nonaqueous fluid injected into the earth's
subsurface through a first wellbore that involves positioning a
fluid analysis tool within a second wellbore and determining the
presence of the injected nonhydrocarbon and nonaqueous fluid by
making a measurement downhole on the injected nonhydrocarbon and
nonaqueous fluid using the fluid analysis tool. Another aspect of
the invention is a method of enhancing hydrocarbon production from
a subsurface area having first and second wellbores that involves
injecting a nonhydrocarbon and nonaqueous fluid into the subsurface
through the first wellbore, positioning a fluid analysis tool
within the second wellbore, and determining the presence of the
injected nonhydrocarbon and nonaqueous fluid by making a
measurement downhole on the injected nonhydrocarbon and nonaqueous
fluid using the fluid analysis tool. A further aspect of the
invention is a method of determining the relative or absolute
quantity of a nonhydrocarbon and nonaqueous fluid injected into the
earth's subsurface through a first wellbore that involves
positioning a fluid analysis tool within a second wellbore,
measuring the near-infrared spectroscopy signature of fluid
downhole using the fluid analysis tool, measuring the downhole
temperature and pressure using the fluid analysis tool, and
estimating a relative or absolute quantity of the injected
nonhydrocarbon and nonaqueous fluid within said downhole fluid
using the measured near-infrared spectroscopy signature, the
temperature, and the pressure to estimate a partial pressure of
hydrocarbon constituents of the downhole fluid. Further details and
features of the invention will become more apparent from the
detailed description that follows.
BRIEF DESCRIPTION OF FIGURES
[0012] The invention will be described in more detail below in
conjunction with the following Figures, in which:
[0013] FIG. 1 schematically illustrates an example of enhanced
hydrocarbon production from a subsurface area using an injected
nonhydrocarbon and nonaqueous fluid and of monitoring the injected
fluid that can be performed in accordance with the inventive
method;
[0014] FIG. 2 is a flowchart depicting processes associated with
certain embodiments of the present invention; and
[0015] FIG. 3 is another flowchart depicting additional processes
associated with certain embodiments of the present invention.
DETAILED DESCRIPTION
[0016] FIG. 1 schematically illustrates an on-shore example of
enhanced hydrocarbon production from a subsurface area using an
injected nonhydrocarbon and nonaqueous fluid and of monitoring the
injected fluid that can be performed in accordance with the
inventive method. In FIG. 1, a Nonhydrocarbon and Nonaqueous Fluid
100 has been injected into a Subsurface Area 102 using a Injector
Wellbore 104, typically referred to herein as a first wellbore. The
injected Nonhydrocarbon and Nonaqueous Fluid 100 has passed through
the subsurface and has been detected by Fluid Analysis Tool 106,
which has been positioned within Producer Wellbore 108. The Fluid
Analysis Tool 106 may be placed within the Producer Wellbore 108 on
wireline, slickline, coiled tubing, or drillpipe, or may be
temporarily, permanently, or semi-permanently installed with the
well completion hardware within Producer Wellbore 108.
[0017] References in this application to a "second wellbore" will
often correspond with a wellbore that is used to produce fluid from
the subsurface area of interest to the surface, although the
inventive methodology is equally as applicable if the second
wellbore was drilled as an observation or monitoring well or was
formerly used as an injector or test well and is now being used to
monitor the nonhydrocarbon and nonaqueous fluid injected into the
subsurface area or as a producer. While the wells shown in FIG. 1
are essentially vertical, the inventive methodology is also
applicable when the wells are deviated, highly deviated, or have
substantially horizontal sections. Often a substantial number of an
Injector Wellbores 104 and Producer Wellbores 108 will be used to
enhance hydrocarbon production from a subsurface area and they may
be laid out in a regular grid pattern, such as a "nine spot"
pattern where eight producing wells are arranged in a square around
a single injector well, for instance.
[0018] When the inventive technique is used in connection with
enhanced oil recovery purposes, the Nonhydrocarbon and Nonaqueous
Fluid 100 will be injected to help mobilize the residual in-situ
hydrocarbons, move them away from Injector Wellbore 104 and toward
Producer Wellbore 108, where they can be pumped to the surface. It
is not uncommon, however, for a particular subsurface area
Reservoir Interval 110 to have one or more High Conductivity Zones
112 that allow the injected Nonhydrocarbon and Nonaqueous Fluid 100
to preferentially flow from the Injector Wellbore 104 to the
Producer Wellbore 108 without sweeping a large fraction of the
Reservoir Interval between the wellbores. These High Conductivity
Zones 112 could consist of high permeability geologic layers
(sometimes referred to as high perm streaks or super K thief zones)
or structural features such as faults or fractures that have
substantially higher permeability than the reservoir rock matrix.
The inventive methodology has been developed to allow these High
Conductivity Zones 112 to be identified and the problems they cause
during enhanced oil recovery operations to be addressed.
[0019] Some of the processes associated with various embodiments of
the present invention are depicted in flowchart form in FIG. 2.
Inventive Process 10 begins with the injection of the
nonhydrocarbon and nonaqueous fluid into a subsurface area through
a first wellbore, which, as discussed above, is typically referred
to as an injector. This is shown in FIG. 1 as Inject Fluid 12. The
fluids injected will typically be a mixture of different chemical
constituents and will almost always have at least chemically
detectable quantities of both hydrocarbons and water. The inventive
methodology may be used even when the fraction of nonhydrocarbon
and nonaqueous fluid in the injected mixture is relatively small,
certainly less than 50% on a mass fraction basis and possibly even
as low as even 1% to 5% of the injected mixture. Typically, the
injected mixture will have significant quantities of either
nitrogen, carbon dioxide, and/or hydrogen sulfide, but other
nonhydrocarbon and nonaqueous fluids may also be used with the
inventive method, such as air, air with some or substantially all
of the oxygen removed, combustion gases, or chemical plant
byproducts or waste streams. It may be desirable to custom
formulate the injected nonhydrocarbon and nonaqueous fluid mixture
on a case by case basis depending on the particular type of
hydrocarbon present in the subsurface area, the cost of the
material, available surface facilities, available wells and
downhole completion hardware, etc. It has been found, for instance,
that a predominantly carbon dioxide fluid dissolves more readily in
certain types of oil when small quantities of impurities, such as
hydrogen sulfide, are present. It may also be desirable to
alternately cycle between injecting nonhydrocarbon and nonaqueous
fluid and injecting water and/or hydrocarbon gas. The produced
fluid may be separated at the surface and the nonhydrocarbon and
nonaqueous fluid may be reinjected into the reservoir.
[0020] A Fluid Analysis Tool is lowered within the second borehole
in Position Tool 14. The Fluid Analysis Tool determines whether the
injected fluid has reached the position in the second wellbore
where the tool is located in Determine Presence of Injected Fluid
16. Various methods for determining the presence of injected
nonhydrocarbon and nonaqueous fluids using a Fluid Analysis Tool
are discussed in detail below. Typically, the Fluid Analysis Tool
is then repositioned in Reposition Tool 18 and the Determine
Presence of Injected Fluid 16 process is repeated.
[0021] The results of these measurements may then be compared in
Compare Measurements 20. The variation of the composition with
position is often the most important attribute to be determined
(i.e. the relative fraction of the injected fluid in the sampled
interval). This may be addressable by performing any of a number of
Fluid Comparison analyses on the physical and/or chemical
measurement(s) of the two fluids in question. See, for instance, L.
Venkataramanan, et al., "System and Methods of Deriving
Differential Fluid Properties of Downhole Fluids", U.S. patent
application Ser. Nos. 11/132,545 and 11/207,043. The Reposition
Tool 18, Determine Presence of Injected Fluid 16, and Compare
Measurements 20 process is typically repeated until all of the
areas within the second wellbore under evaluation have been
tested.
[0022] If one or more areas within the second wellbore that have
high concentrations of the injected nonhydrocarbon and nonaqueous
fluid are identified (shown in FIG. 2 as Identify Location Having
High Concentration 22), a well treatment may be performed to
enhance production (shown in FIG. 2 as Treat Well 24). This well
treatment may inhibit fluid from entering the wellbore at the
identified location and flowing to the surface, such as the
installation of a bridge plug, a packer, a casing patch, gel, or
cement at a location within the wellbore that inhibits such fluid
flow. Alternately, the well treatment could enhance the production
of fluid entering the wellbore from areas other than the identified
location, such as by pressure fracturing, propellant fracturing,
acidizing, or reperforating these other areas.
[0023] It is also possible to utilize the information obtained
regarding the presence of nonhydrocarbon and nonaqueous fluid to
simulate the dynamic behavior of the reservoir (shown in FIG. 2 as
Simulate Reservoir 26) and to adjust the rate of production from
the producer well (and typically the rates of production of any
other producer wells associated with the injector well) to optimize
the sweep of the subsurface area. This is shown in FIG. 2 as Modify
Production Rate 28. After a period of time, the entire process
described above may be repeated.
[0024] There are numerous alternative types of measurements that
can be used to determine the presence of the injected fluid. If the
injected fluid/hydrocarbon mixture in the reservoir or in the
producer wellbore becomes so saturated with injected fluid that the
gas phase separates from the liquid phase, then known methods of
gas phase detection can be used such as those described in
"Apparatus and method for detecting the presence of gas in a
borehole flow stream", Mullins, Hines, Niwa and Safinya, U.S. Pat.
No. 5,167,149 (1993) and "Apparatus and method for detecting the
presence of gas in a borehole flow stream", Mullins, Hines, Niwa
and Safinya, U.S. Pat. No. 5,201,220 (1994). It is also possible to
detect evolved bubbles of injected gas as fluid enters the second
wellbore or as it travels up the wellbore and the ambient pressure
is reduced using oilfield production logging tools such as the Flow
Scanner.TM. or GHOST.TM. tools available from Schlumberger.
[0025] If all or some of the injected gas dissolves in (i.e. is
miscible with) the formation fluid, then the fluid phase transition
parameters change and this can be detected before the fluid begins
to separate into different gas and liquid phases. These parameters
include bubble point, dew point and asphaltene onset pressures. For
example, if the pressure is sufficiently high, significant
quantities of nitrogen can dissolve in oil. Nitrogen is not
particularly soluble in oil in comparison to methane; thus,
dissolved nitrogen would tend to come out of solution at much
higher pressures than would equivalent quantities of methane. One
can therefore map phase transition pressure as a function of
position in a reservoir as a way to map injected fluid progression
within the reservoir. In particular sensitive methods of gas
detection are ideal for this purpose. Ultrasonic detection of gas
phase evolution in a continuous liquid phase is one such method.
See, for instance, "Method and Apparatus for the Detection of
Bubble Point Pressure", Bostrom, Griffin, and Kleinberg, U.S. Pat.
No. 6,758,090 (2004).
[0026] If the injected gas has a separate signature from
hydrocarbons, then this different signature can monitored along
with any hydrocarbon signature to map volume or mass fractions of
formation fluid vs. injected fluid. Such is the case for CO.sub.2
if near-infrared spectroscopy (NIR) is used. See, for instance,
"Method of detecting CO.sub.2 in a downhole environment", Mullins,
Rabbito, McGowan, Terabayashi, and Kazuyoshi, U.S. Pat. No.
6,465,775 (2002)
[0027] Many gases, however, do not possess a strong NIR signature.
Diatomic nitrogen (the nitrogen in air) has no NIR absorption, this
because it has a center of symmetry. Thus, there can be no change
in electric dipole moment with stretching of the nitrogen bond.
Thus, one cannot detect nitrogen by standard NIR absorption
methods.
[0028] Other gases such as H.sub.2S have exceedingly weak NIR
signatures. For cases such as N.sub.2 or H.sub.2S, an issue remains
regarding how they may be detected using NIR measurements. Consider
the extreme case of pure nitrogen under downhole conditions of high
pressure. Here the NIR spectrometer would indicate the absence of
any hydrocarbons by virtue of the lack of any NIR hydrocarbon
absorption. However, the pressure is high indicating there is no
vacuum. In the case of nitrogen injection into a hydrocarbon field,
the only gas that could be present without hydrocarbon absorption
features yet with high pressure is nitrogen. Consequently, one can
detect nitrogen because it represents the `missing mass` in this
measurement.
[0029] In fact, one can calculate the mass density or quantity of
nitrogen by knowing the pressure, temperature, and compressibility
factor Z for nitrogen at the measured downhole pressure and
temperature conditions. Consider the less than extreme case where
there is a small quantity of hydrocarbon present in a large
quantity of nitrogen. Here, the observed hydrocarbon absorption
bands would be too small to account for the measured high pressure
analysis conditions. It has been established in "Linearity of
alkane near-infrared spectra", Mullins, Joshi, Groenzin, Daigle,
Crowell, Joseph, and Jamaluddin, Appl. Spectros. 54, 624, (2000)
that the NIR hydrocarbon bands are linear in the mass density of
the hydrocarbon. One can therefore calculate the partial pressure
of the hydrocarbon constituents of the sample. The remaining
pressure would then be presumed to result from nitrogen. Any of the
various known mixing laws would be presumed for the
hydrocarbon/nitrogen mixture at reduced pressure and temperature.
For instance, certain mixing laws were presumed for nitrogen helium
mixtures for downhole conditions of pressure and temperature in
"Gas detector response to high pressure gases", Mullins, Schroeder,
Rabbito, Applied Optics, 33, 7963 (1994)
[0030] These reduced variables can then be used to obtain a
compressibility factor that is then compared with the measured
pressure temperature and hydrocarbon band size. Composition
adjustments may be made to obtain a self consistent mixture
composition giving proper NIR hydrocarbon peak sizes at the proper
pressure and temperature conditions.
[0031] This process is illustrated in FIG. 3, where the process of
Determine Presence of Injected Fluid 16 is shown as consisting of
Measure NIR Signature 161, followed by Measure Temperature and
Pressure 162, and Estimate Concentration 163.
[0032] Alternative methods for detecting fluids such as hydrogen
sulfide downhole are described in "Hydrogen sulfide detection
method and apparatus", Jiang, Jones, Mullins and Wu, U.S. Pat. No.
6,939,717 (2005) and "Methods and apparatus for the measurement of
hydrogen sulphide and thiols in fluids", Jiang, Jones, Brown and
Gilbert, U.S. patent application Ser. No. 10/541,568, filed May 28,
2003.
[0033] Downhole gas chromatography is another way to achieve the
direct detection of nitrogen or other types of injected
nonhydrocarbon and nonaqueous fluids. Downhole equipment and
methods of the type described in "Self-Contained Chromatography
System", Bostrom and Kleinberg, U.S. patent application Ser. No.
11/296,150, filed Nov. 21, 2006 and "Heat Switch for
Chromatographic System and Method of Operation", Bostrom, Daito,
Shah, and Kleinberg, U.S. patent application Ser. No. 11/615,426,
filed Dec. 22, 2006 may, for instance, be used in connection with
this process. Relatively high concentrations of nitrogen may,
however, need to be present in the oil to detect the missing mass
using downhole gas chromatography methods. The use of gas
chromatography to detect nitrogen, carbon dioxide, and hydrogen
sulfide is shown in Varian GC Application Note Number 29, a copy of
which may be found at
https://www.varianinc.com/media/sci/apps/gc29.pdf. However, NIR
analysis of the separated gas phase may be much more sensitive to
see the missing mass created by significant quantities of nitrogen.
Consequently, intentionally causing a phase change and performing
NIR analysis of the gas would be preferred to detect the presence
and quantity of significant amounts of gas.
[0034] It is also possible to detect the presence of the injected
fluids or a chemical product that indicates the presence of the
injected fluid by using one or more chemical sensors. Examples of
the types of chemical sensors that may be utilized with the
inventive method can be found in "Systems and method for sensing
using diamond based microelectrodes", Jiang, Jones and Hall, U.S.
patent application Ser. No. 10/638,610, filed Aug. 11, 2003 and
"Fluid property sensors", Goodwin, Donzier, Manrique, Pelham and
Meeten, U.S. patent application Ser. No. 10/104,495, filed Mar. 22,
2002.
[0035] All documents referenced herein are incorporated by
reference. While the invention has been described herein with
reference to certain examples and embodiments, it will be evident
that various modifications and changes may be made to the
embodiments described above without departing from the scope of the
invention as set forth in the claims.
* * * * *
References