US20120125602A1

US20120125602A1 - Monitoring Injected Nonhydrocarbon And Nonaqueous Fluids Through Downhole Fluid Analysis

Info

Publication number: US20120125602A1
Application number: US13/269,954
Authority: US
Inventors: Francois Dubost; Oliver C. Mullins; Lalitha Venkataramanan; Christopher Harrison; Neil Bostrom; Robert Kleinberg
Original assignee: Individual
Current assignee: Individual
Priority date: 2006-06-01
Filing date: 2011-10-10
Publication date: 2012-05-24
Also published as: US20080135237A1

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.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

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

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

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.
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.
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.
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.
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.
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).
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).
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

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

The invention will be described in more detail below in conjunction with the following Figures, in which:

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;

FIG. 2 is a flowchart depicting processes associated with certain embodiments of the present invention; and

FIG. 3 is another flowchart depicting additional processes associated with certain embodiments of the present invention.

DETAILED DESCRIPTION

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.
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.
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.
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.
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.
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.
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.
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.
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™ or GHOST™ tools available from Schlumberger.
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).
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 CO₂if near-infrared spectroscopy (NIR) is used. See, for instance, “Method of detecting CO₂in a downhole environment”, Mullins, Rabbito, McGowan, Terabayashi, and Kazuyoshi, U.S. Pat. No. 6,465,775 (2002)
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.
Other gases such as H₂S have exceedingly weak NIR signatures. For cases such as N₂or H₂S, 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.
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)
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.
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.
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.
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.
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.
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.

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.