MONITORING OF NON-HYDROCARBON AND NON-AQUEOUS FLUIDS INJECTED,
THROUGH THE ANALYSIS OF FLUIDS IN THE DRILL FUND
FIELD OF THE INVENTION This invention relates to the monitoring of non-hydrocarbon and non-aqueous fluids that are injected into the lower surface of the Earth and, more particularly, to the methods for monitoring the non-hydrocarbon and non-aqueous fluids that are * injected into the lower surface or sub-surface of the Earth through the use of fluid analysis at the bottom of the drilling and / or related techniques, particularly in connection with the improvement of hydrocarbon production of a sub-surface area. BACKGROUND OF THE INVENTION In certain hydrocarbon reservoirs, such as the giant Cantarell field in Mexico, non-hydrocarbon and non-aqueous fluids are injected to improve the production of hydrocarbons. In the Cantarell field, one trillion 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 injected into the Weyburn field in Saskatchewan, Canada for enhanced oil recovery and for carbon dioxide inhibition purposes. geological.
These types of hydrocarbon production techniques are typically called improved or tertiary recovery techniques. It is of central interest to understand the disposition of the injected fluids. Clearly, if the injected fluid is diverted from the oil bags or if the fluid does not reach equilibrium concentrations in the hydrocarbons instead, either gas or oil, then the efficiency of the production improvement can be greatly compromised. It is also possible that the injected fluids escape the intended geologic deposit interval and potentially migrate back to the surface. Using known techniques, several samples could be acquired at the bottom of the hole as a function of position in the deposit and analysis at the well site or in the laboratory of the acquired samples. With this information, one might expect to track the trajectory of the non-hydrocarbon and non-aqueous fluids injected. A significant problem with this methodology is that it is difficult to adequately investigate similar complexities of fluid and deposit using a reasonable sample acquisition program because the fluid sampling tools at the bottom of the borehole typically
they can acquire a very limited number of samples, typically less than ten, in a single run of the chart. It is also possible to acquire samples of the fluid produced on the surface and analyze the concentration of the fluid injected into the fluid produced, but when the fluid reaches the surface, it is typically difficult or impossible to accurately determine the fraction of the fluid injected into the reservoir fluid as it enters. in the borehole or determine where the injected fluid enters the borehole. Fluid Analysis in the Drilling Bottom (DFA), a set of diagnostic services developed by Schlumberger primarily for the environment of openhole hydrocarbon exploration wells, enables the real-time evaluation of fluid composition while sampling thus allowing modification of the sample analysis program of the planned reservoir as appropriate to further evaluate the complexities of the fluid as they are discovered. In a well, if it is found by a prudent selection of the DFA station that a complete fluid column is effectively homogeneous then a smaller analysis can be performed. However, if significant fluid complexities are discovered, then additional tests of the DFA station may be performed. This
is, if the evaluation program does not require filling (a necessarily finite number of) sample jars, then a program of evaluation of the fluid in the bottom of the perforation does not have to be suspended simply because all the available sample vials have been filled. Of course, if corroboration of the DFA results is desired, then the acquisition and analysis of samples at the bottom of the borehole can be followed by the analysis of the surface and can be used to complement the analysis at the bottom of the borehole. If the fluid injected for production improvement is water, then existing methods of oil-water or gas-water differentiation could be used to monitor the progress of the water injected through the reservoir. See, for example, "Method of analyzing oil and water flow streams," Hiñes, Wada, Mullins, Tarvin, and Cramer, US Patent No. 5,331,156 (1995). If the injected fluid is hydrocarbon gas, then the standard DFA determination methods of the gas-oil ratio could be used. This type of method is described in "Method and Apparatus for Downhole Compositional Analysis of Formation Gases", Mullins and Wu, North American Patent No. 5,859,430 (1999) and "Method and Apparatus for Determination Gas-Oil Ratio
In a Geologic Formation through the use of spectroscopy, "Mullins, US Patent No. 5,939,717 (1999). If the methane or spacer gas is injected into the reservoir, the methods for performing the DFA could be used to determine the composition of the In particular, near-infrared spectroscopy is currently used to quantify methane, other hydrocarbon gases, and hydrocarbons of higher molecular weights, see for example, "Method and apparatus for determining chemical composition of reservoir fluids", Fujisawa, Mullins , Van Agthoven, Rabbito, and Jenet, US Patent No. 7,095,012 (2006) However, if the predominant components of the injected fluid are different from hydrocarbons and water, new methods are required to monitor the progress of injected fluids and / o to improve the production of hydrocarbons from the lower surface or sub-surface in which the fluids are injected. CRIPTION OF THE INVENTION One aspect of the invention is a method of monitoring a non-hydrocarbon and non-aqueous fluid injected into the lower surface of the earth through a first drilling, which involves positioning a fluid analysis tool within a second drilling and
determine the presence of the non-hydrocarbon and nonaqueous fluid injected by making measurements at the bottom of the borehole on the non-hydrocarbon and non-aqueous fluid injected using the fluid analysis tool. Another aspect of the invention is a method for improving the production of hydrocarbons from a sub-surface area having first and second boreholes, which involves injecting a non-hydrocarbon and non-aqueous fluid into the sub-surface through the first bore, positioning a fluid analysis tool within the second borehole, and determine the presence of the non-hydrocarbon and nonaqueous fluid injected by making a measurement at the bottom of the bore in the non-hydrocarbon and non-aqueous fluid injected using the fluid analysis tool. A further aspect of the invention is a method for determining the relative or absolute amount of a non-hydrocarbon and non-aqueous fluid injected into the lower surface of the earth through a first bore, which involves positioning a fluid analysis tool within the a second perforation, measure the near-infrared spectroscopic signature of the fluid at the bottom of the borehole using the fluid analysis tool, measure the temperature and pressure at the bottom of the borehole using the fluid analysis tool, and estimate a relative or absolute amount of the fluid not
hydrocarbon and nonaqueous injected into said fluid at the bottom of the borehole using the near infrared spectroscopic signature, temperature and pressure to estimate a partial pressure of hydrocarbon constituents of the fluid at the bottom of the borehole. The details and additional features of the invention will be more apparent from the detailed description that follows. BRIEF DESCRIPTION OF THE FIGURES The invention will be described below in more detail in conjunction with the following Figures, in which: Figure 1 illustrates schematically an example of improved hydrocarbon production from a sub-surface area using a non-hydrocarbon and non-aqueous fluid injection and monitoring of the injected fluid that can be carried out according to the inventive method; Figure 2 is a flowchart representing processes associated with certain embodiments of the present invention; and Figure 3 is another flow chart depicting additional processes associated with certain embodiments of the present invention. DETAILED DESCRIPTION OF THE INVENTION Figure 1 schematically illustrates an example on land of improved hydrocarbon production from a sub-surface area.
surface using a non-hydrocarbon and non-aqueous fluid injected and monitoring the injected fluid, which can be made according to the inventive method. In Figure 1, a Non-Hydrocarbon and Non-Aqueous Fluid 100 is injected into a Sub-surface Area 102 using a Probe 104 Injector, typically referred to herein as a first perforation. The non-hydrocarbon and non-aqueous Fluid 100 injected passes through the lower surface and is detected by the Fluid Analysis Tool 106, which is located within the Producer Probe. The Fluid Analysis Tool 106 may be placed within the Producer Probe 108 in the wiring, oily spot, spiral pipe or drill pipe, or may be installed temporarily, permanently, or semi-permanently with the hardware or physical equipment of the completion of the well inside Producer 108 Producer. References in this application for a "second drilling" will often correspond to a drilling that is used to produce fluid from the sub-surface area of interest to the surface, although the inventive methodology is equally applicable if the second drilling was drilled as a observation or monitoring well or was formerly used as an injector or test well and is now being used to monitor the non-hydrocarbon and non-aqueous fluid injected into the sub-surface area or as a
producer. While the wells shown in Figure 1 are essentially vertical, the inventive methodology is also applicable when the wells are deviated, highly deviated, or have substantially horizontal sections. A substantial number of Probes 104 Probes and Probes 108 are often used to improve the production of hydrocarbons from a sub-surface area and can be placed in a regular grid pattern, such as a "nine point" pattern where they are arranged eight producing wells in a square around a single injector well, for example. When the inventive technique is used in connection with improved oil recovery purposes, the non-hydrocarbon and non-aqueous Fluid 100 is injected to help mobilize the residual hydrocarbons in-situ, move them away from the Injector Probe 104 and into the Producer Probe 108, where they can be pumped to the surface. It is not uncommon, however, for a Reservoir Interval 110 of the particular sub-surface area to have one or more High Conductivity Zones 112 that allow the 100 Hydrocarbon and Non-Aqueous Fluid injected to flow preferably from the Probe 104 Injector to the Probe 108 Producer without sweeping a large fragment of the Reservoir Interval between the perforations. These High Conductivity Zones 112 could consist of high permeability geological layers (sometimes referred to as veins of
high permeability or super K) escape 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 identify these High Conductivity Zones 112 and the problems they cause during the oil recovery operations that are going to be applied. Some of the processes associated with various embodiments of the present invention are represented in the form of a flow diagram in Figure 2. The Inventive Process 10 begins with the injection of the non-hydrocarbon and non-aqueous fluid in a sub-surface area through a first piercing, which, as described above, is typically referred to as an injector. This is shown in Figure 1 as Injection Fluid 12. The injected fluids will typically be a mixture of different chemical components and will almost always have at least chemically detectable amounts of both hydrocarbons and water. The inventive methodology can be used even when the fraction of the non-hydrocarbon and non-aqueous fluid in the injected mixture is relatively small, certainly less than 50% on a mass fraction basis and possibly even as low as 1% to 5% of the mixture. injected. Typically, the injected mixture will have
significant of either nitrogen, carbon dioxide, and / or hydrogen sulfide, but other non-hydrocarbon and non-aqueous 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 byproducts of chemical plants or waste streams. It may be desirable to custom formulate the mixture of the non-hydrocarbon and non-aqueous fluid injected on a case-by-case basis depending on the particular type of hydrocarbon present in the sub-surface area, the cost of the material, available surface facilities, available wells and hardware or physical equipment completion of the drilling, etc. It has been found, for example, that a predominantly carbon dioxide fluid dissolves more readily in certain types of oil when small amounts of impurities, such as hydrogen sulfide, are present. It may also be desirable to cycle alternately between injecting the non-hydrocarbon and non-aqueous fluid and injecting water and / or hydrocarbon gas. The fluid produced can be separated at the surface and the non-hydrocarbon and non-aqueous fluid can be reinjected into the reservoir or reservoir. A Fluid Analysis Tool is lowered into the second probing well in Position Tool 14. The Fluid Analysis Tool determines if
the injected fluid has reached the position in the second perforation where the tool is located in Determine the Presence of the Fluid 16 Injected. Below, various methods to determine the presence of non-hydrocarbon and non-aqueous fluids injected using a Fluid Analysis Tool are described in detail. Typically, the Fluid Analysis Tool is subsequently repositioned in the Replacement Tool 18 and the process for determining the presence of the Injected Fluid 16 is repeated. The results of these measurements can then be compared in Comparison Measurements. The variation of the composition with the position is often the most important attribute to be determined (ie, the relative fraction of the fluid injected in the tested range). This may be applicable by performing any number of Fluid Comparison analysis on the physical and / or chemical measurement (s) of the two fluids in question. See, for example, L. Venkataramanan, et al., "System and Methods of Deriving Differential Fluid Properties of Downhole Fluids", North American Patent Application Series Nos. 11 / 132,545 and 11 / 207,043. The Replacement Tool 18, Determine the Presence of Injected Fluid 16, and the Comparison Measurement process 20 are typically repeated until they have been
tested all areas within the second drilling under evaluation. If one or more areas are identified within the second borehole that has high concentrations of the non-hydrocarbon and non-aqueous injected fluid (shown in Figure 2 as Identifying the Location having the Highest Concentration 22), then a well treatment can be performed to improve production (shown in Figure 2 as Well 24 of Treatment). This well treatment can inhibit the fluid from entering the borehole at the identified location and flowing to the surface, such as the installation of a stopper plug, a shutter, tight fitting, gel or cement at a location within the borehole. which inhibits such fluid from flowing. Alternatively, the treatment of the well could improve the production of fluid entering the drilling from other areas apart from the identified location, such as by pressure fracture, propeller fracture, acidification or reperforating these other areas. It is also possible to use the information obtained regarding the presence of the non-hydrocarbon and non-aqueous fluid to simulate the dynamic behavior of the deposit (shown in Figure 2 as reservoir 26 of simulation) and adjust the production rate of the producer well (and
typically the production rates of any of the other producing wells are associated with the injector well) to optimize the sweep of the sub-surface area. This is shown in Figure 2 as Speed 28 of Modified Production. After a period of time, the entire process described above can be repeated. There are numerous types of measurement alternatives that can be used to determine the presence of the injected fluid. If the fluid / hydrocarbon mixture injected into the producer tank or borehole becomes so saturated with the injected fluid that the gas phase is separated from the liquid phase, then known gas phase detection methods such as those described in US Pat. "Apparatus and method for detecting the presence of gas in a borehole flow stream", Mullins, Hiñes, Niwa and Safinya, North American Patent No. 5,167,149 (1993) and "Apparatus and method for detecting the presence of gas in a borehole flow stream" , Mullins, Hiñes, Niwa and Safinya, North American Patent No. 5,201,220 (1994). It is also possible to detect bubbles developed from gas injected while the fluid enters the second borehole or while traveling up the borehole and atmospheric pressure is reduced using logging tools for the production of fields
petroleum products such as the Flow Scanner or GHOST ™ tools available from Schlumberger. If all or part of the injected gas dissolves in (that is, is miscible with) the formation fluid, then the fluid phase transition parameters change and this can be detected before the fluid starts to separate into different gas phases and liquid These parameters include bubble point pressure, dew point pressure and asphaltene appearance pressure. For example, if the pressure is high enough, then significant amounts of nitrogen can be dissolved in oil. Nitrogen is not particularly soluble in oil compared to methane; thus, dissolved nitrogen would tend to be stripped of the solution at very high pressures that would equal the methane amounts. It is therefore possible to form a map of the phase transition pressure as a position function in a tank in order to form a map of the progression of the fluid injected into the tank. In particular, sensitive gas detection methods are ideal for this purpose. Ultrasonic detection of the evolution of the gas phase in a continuous liquid phase is one such method. See, for example, "Method and Apparatus for the Detection of Bubble Point Pressure",
Bostrom, Griffin, and leinberg, North American Patent No.
6, 758, 090 (2004). If the injected gas has a separate signature of the hydrocarbons, then this different signature can be monitored along with any hydrocarbon signature to map the volume or mass fractions of the formation fluid against the injected fluid. Such is the case for the
C02 if near infrared spectroscopy (NIR) is used.
See, for example, "Method of detecting C02 in a downhole environment," Mullins, Rabbito, McGowan, Terabayashi, and azuyoshi, US Patent No. 6,465,775 (2002). Many gases, however, do not have a firm NIR signature.
Diatomic nitrogen (nitrogen in air) has no NIR absorption, this because it has a center of symmetry. Thus, there can be no change in the electric dipole moment with the lengthening of the nitrogen bond. Thus, nitrogen can not be detected by standard absorption methods
NIR Other gases such as ¾S have weak NIR surplus characteristics. For such cases, such as N2 or ¾S, a problem remains in relation to how they can be detected using NIR measurements. Consider the extreme case of pure nitrogen under high pressure conditions at the bottom of the borehole. Here the NIR spectrometer would indicate the
absence of any hydrocarbon by virtue of the lack of any NIR hydrocarbon absorption. However, the pressure is high indicating that there is no vacuum. In case of nitrogen injection in a hydrocarbon field, the only gas that could be present without the hydrocarbon absorption characteristics but with high pressure is nitrogen. Consequently, nitrogen can be detected because it represents the 'lost mass' in this measure. In fact, one can calculate the density of mass or the amount of nitrogen by knowing the pressure, temperature, and the compressibility factor Z for nitrogen under the conditions of pressure and temperature measured at the bottom of the borehole. Consider the less extreme case where there is a small amount of hydrocarbons present in a large amount of nitrogen. Here the observed absorption bands of the hydrocarbon would be very small to be counted for the conditions of the measured high pressure analysis. It has been established in "Linearity of alkane near-infrared spectra", Mullins, Joshi, Groenzin, Daigle, Crowell, Joseph, and Jamaluddin, Appl. Specters. 54, 624, (2000) that the NIR hydrocarbon bands are linear in the mass density of the hydrocarbon. The partial pressure of the hydrocarbon components of the test can therefore be calculated. It would then be assumed that the remaining pressure results from
nitrogen. Any of the various known mixing laws would be assumed for the hydrocarbon / nitrogen mixture at reduced temperature and pressure. For example, certain mixing laws are assumed for mixtures of helium nitrogen for conditions at the bottom of the pressure and temperature drilling 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 hydrocarbon band size, temperature and pressure. Composition adjustments can be made to obtain a self-consistent mixing composition by giving correct NIR hydrocarbon peak sizes at the correct pressure and temperature conditions. This process is illustrated in Figure 3, where the process of Determining the Presence of Injected 16 Fluid is shown as consisting of Signature 161 NIR Measurement, followed by Temperature and Pressure 162 Measurement, and Concentration 163 Estimated. Alternative methods for detecting fluids such as hydrogen sulphide at the bottom of the perforation are described in "Hydrogen sulfide detection method and apparatus", Jiang, Jones, Mullins and Wu, American Patent
No. 6,939,717 (2005) and "Methods and apparatus for the temptation of hydrogen sulphide and thiols in fluids", Jiang, Jones, Brown and Gilbert, US Patent Application No. 10 / 541,568, filed May 28, 2003. Gas chromatography at the bottom of the hole is another way to achieve direct detection of nitrogen or other types of non-hydrocarbon and non-aqueous fluids injected. The equipment and methods at the bottom of the drilling of the type described in "Self-Contained Chromatography System", Bostrom and Kleinberg, US Patent Application Series No. 11 / 296,150, filed November 21, 2006 and "Heat Switch for Chromatographic System and Method of Operation, "Bostrom, Daito, Shah, and Kleinberg, US Patent Application Series No. 11 / 615,426, filed December 22, 2006 may, for example, be used in connection with this process. Relatively high concentrations of nitrogen may, however, need to be present in the oil to detect the mass lost using gas chromatography methods at the bottom of the borehole. The use of gas chromatography to detect nitrogen, carbon dioxide, and hydrogen sulfide is shown in note number 29 of the Varian GC Application, a copy of which can be found at https: // www. varianiñe. com / media / sci / apps / gc29.pdf. Without
However, the NIR analysis of the separated gas phase can be much more sensitive to see the mass lost created by significant amounts of nitrogen. Consequently, it would be preferred to intentionally cause a phase change and perform the NIR analysis of the gas to detect the presence and * the amount of significant amounts of gas. It is also possible to detect the presence of the injected fluids or a chemical that indicates the presence of the injected fluid using one or more chemical sensors. Examples of the types of chemical sensors that can be used with the inventive method can be found in "Systems and method for sensing using diamond based microelectrodes", Jiang, Jones and Hall, US Patent Application No. 10 / 638.6 10, filed on August 11, 2003 and "Fluid property sensors", Goodwin, Donzier, Manrique, Pelham and Meeten, US Patent Application No. 10 / 104,495, filed on March 22, 2002. All the documents for which it was established References here are incorporated as a reference. While the invention has been described herein with reference to certain examples and embodiments, it will be apparent 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.