RU2373523C2 - Method (versions) and device for analysing properties of emulsion fluid using fluoresence spectroscopy - Google Patents

Abstract

FIELD: physics.

SUBSTANCE: invention relates to analysis of samples using fluorescence spectroscopy. The invention employs a fluid extraction unit, an optical cell, a radiation source and a unit for detecting fluid fluorescence. The radiation source and the detection unit lie next to the optical cell. The invention uses apparatus for collecting a fluorescence signal from the extracted fluid when in a well for analysis of fluid properties. The method also involves detection of changes in properties (gradients) of fluid of the oil column.

EFFECT: possibility of efficient well analysis of fluid in samples of heavy oil in the presence of a water/oil emulsion, as well as in the presence of fine particles, such as uncompacted sand, in the oil.

29 cl, 11 dwg

Description

RELATED APPLICATIONS

This application claims the priority of a provisional application for the grant of a US patent No. 60 / 837,471, registered August 14, 2006 and entitled "Methods and Apparatus for Analyzing Fluid Properties of Emulsions Using Fluorescence Spectroscopy" ("Methods and apparatus for analyzing the properties of emulsion fluids using fluorescence spectroscopy ").

FIELD OF TECHNOLOGY

This invention relates to analysis of samples by fluorescence spectroscopy.

BACKGROUND

A study of hydrocarbon fluorescence for downhole assessment of formation fluids using a wireline logging tool has been disclosed in numerous patents (e.g., U.S. Patents Nos. 2,206,922; 2,346,481; 2,334,475; 6,140,637 and 6,268,603, each of which is incorporated by reference). As described in one or more of the patents identified above, the proposed methods are generally aimed at moving a logging tool launched on a cable along the wellbore along with irradiation of the formation. Prior art methods disclose fluorescence detection through an optically transparent material that is pressed against a borehole wall. However, in order to be useful to any degree, the transparent material must be pressed against the wall of the wellbore with sufficient force to displace the mud cake. Unfortunately, the natural fluorescence of some shale and hydrocarbon bearing rocks complicates the interpretation of well logs, and methods known from the prior art have not been widely used.

Schlumberger's Modular Dynamic Reservoir Tester (MDT ™) collects numerous samples at any number of locations in the borehole. Formation fluids are hydraulically separated from the drilling fluids (and mud cake) in the borehole. The formation fluid is drawn into the flow line inside the MDT tool body and analyzed using absorption spectroscopy through a sapphire optical cell. Routine pollution control tells the operator when to take a sample. GOR (gas factor - ratio of produced gas to produced oil) and compositional information can be determined by the LFA ™ tool and CFA ™ tool, respectively. However, since the number of selected MDT flasks available for MDT is limited, some technical solutions have suggested a quasi-continuous log of reservoir fluids that could be formed without collecting samples. Obtaining a quasi-continuous log without collecting samples is generally referred to as “rinsing”. Rinsing methods are disclosed in US patents with numbers: 6,476,384; 6,465,775; 5,859,430 and 5,939,717, each of which is incorporated by reference.

SUMMARY OF THE INVENTION

The present disclosure aims to address the disadvantages of the prior art described above. More specifically, one embodiment provides a method for analyzing fluid properties. The method comprises preparing a downhole fluid analysis device, extracting fluid from the wellbore using a downhole fluid analysis device, drawing fluid into the downhole fluid analysis device and receiving a fluorescence signal (i.e., any fluorescence parameters) from the fluid while in the well. In one embodiment, obtaining a fluorescence signal comprises irradiating a fluid through an optical cuvette and detecting fluorescence. One embodiment of the method further includes moving the downhole fluid analysis device along the wellbore, and retrieving, retracting and receiving at multiple locations along the wellbore.

In one embodiment, the method further comprises identifying fluid composition gradients in the fluid column by comparing fluorescence signals at two or more of the multiple locations along the wellbore. One of the methods further comprises releasing the fluid back from the downhole fluid analysis device and forming a quasi-continuous fluid log without sample collection. In one embodiment, the method further comprises comparing the fluorescence signal with known fluorescence spectra and identifying the fluid based on comparing the fluorescence signal of the fluid with known fluorescence spectra. In one embodiment, the method further comprises comparing the fluorescence signal with known fluorescence spectra while in the well and identifying the fluid based on comparing the fluorescence signal of the fluid with known fluorescence spectra while in the well. One embodiment further comprises correlating the fluorescence signal and other physical characteristics of the fluid to form a database. Other physical characteristics may contain one or more of the weight fraction of asphaltenes, density, viscosity, and C36 +.

One embodiment of a method for analyzing fluid properties further comprises correlating a fluorescence signal with other logging or logging data while drilling. One embodiment further comprises identifying the relationships between the fluorescence signal and the logging or logging data while drilling. Other embodiments further comprise correlating the fluorescence signal with other logging or logging data while drilling and creating models or tables to assist in interpreting the fluorescence signal.

One aspect provides a method for identifying fluid composition gradients in an oil column. The method includes moving the fluid analysis device along the wellbore, fixing the fluid analysis tool at the desired sampling interval, extracting the fluid from the formation adjacent to the wellbore into the flow line in the device body, irradiating the fluid in the flow line through an optical cuvette inserted in the flow line , and fluorescence detection. In one embodiment, the method comprises identifying fluid composition gradients in a fluid column by comparing fluorescence signals along a sampling interval. Some embodiments further comprise comparing the resulting fluorescence detection with known fluorescence spectra and identifying the fluid based on a comparison of the detected fluorescence with known fluorescence spectra. In one embodiment, the distance between fixations in the sampling interval is regular or irregular. In one embodiment, the irradiation is performed using light with a wavelength in the UV (ultraviolet, UV) region.

One aspect provides a method for analyzing a sample, comprising collecting fluorescence parameters from a formation sample while in a well at multiple locations, and analyzing changes in fluorescence at two or more of the multiple locations to determine if the sample is the same or different at two or more multiple locations . One embodiment of the invention comprises monitoring the color of the formation sample at multiple locations and correlating changes in fluorescence parameters with changes in color of the fluid. One embodiment further comprises using changes in fluorescence parameters to determine if there are cavities with fluid within the formation. In one embodiment, the method further comprises analyzing the structure of the fluorescence parameters over an extended depth interval and forming an indication of the physical property correlated with fluorescence. In one embodiment, the method further comprises correlating fluorescence parameters with other log data, identifying relationships between fluorescence parameters and other log data, and creating models or rules to assist in interpreting other well logs. In some embodiments, fluorescence parameters can form a quasi-continuous log. Moreover, the reservoir sample may contain an aqueous / oil emulsion.

One embodiment provides a device comprising a downhole fluid analysis device. The downhole fluid analysis device comprises a fluid extraction module comprising a flow line, an optical cuvette located in the flow line, a radiation source in the optical cuvette, and a fluorescence detection unit in the optical cuvette. One embodiment also includes a fluid color control module. In one embodiment, the radiation source comprises an LED (light emitting diode, LED) or a laser diode capable of generating visible ultraviolet and / or infrared light.

One aspect of the invention provides a method comprising modifying an existing downhole fluid analysis device with a fluorescence detection unit. The method may include modifying the downhole fluid analysis device with a UV light source.

Some aspects provide a method and apparatus for identifying composition gradients in an oil column using fluorescence spectroscopy, which may or may not contain an emulsion. One of the methods includes moving the device along the well, fixing the device at the required sampling interval, extracting fluid from the formation into the tool body, irradiating the fluid in the flow line through an optical cuvette inserted in the flow line, and detecting fluorescence. The light source may be visible ultraviolet or infrared, or any combination thereof. These light sources (ohms) may be LED (s) or laser diode (s). The fluorescence signal is detected on the front surface of the optical cell.

The description below establishes the relationship between the metric extracted from the fluorescence signal or spectrum, such as the strip area or peak height, and the desired oil property. Inside the oil column, the correlation between fluorescence and oil color is such that the metric can be used to detect changes in fluid composition and / or concentration changes within the oil column. Thus, by changing the fluorescence signal, it is possible to determine whether there is a compositional gradient within the sand horizon and, moreover, to identify fluid cavities (in particular, columns of heavy oil are often stepwise changing due to biochemical decomposition).

Some aspects apply to heavy oil samples in which a water / oil emulsion has been created due to water-based drilling fluids used for drilling. Emulsions affect absorption measurements, as water droplets scatter light, preventing it from reaching the detector. However, it will be understood by one skilled in the art that fluorescence can be used instead of displaying compositional changes and other properties on the map (for example, fluorescence can be correlated with oil color or other properties or parameters).

One aspect uses this technology to perform quasi-continuous logging without sample collection in order to quickly detect composition changes in an oil column. One aspect improves the analysis of GOR and composition.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings illustrate some embodiments of the invention and are part of the description of the invention.

FIG. 1 shows a wellbore MDT device that may be modified or equipped with a fluorescence detector (FDU) assembly, such as the FDU shown in FIG. 2.

Figure 2 shows a diagram of an absorption spectrometer CFA ™ and FDU.

Figure 3 shows the effect of a water / oil emulsion on the absorption spectra of heavy oil from a geographic area in the Middle East.

Figure 4 shows the fluorescence spectra for the same heavy oil associated with figure 3, with the same relative fractions of water.

Figure 5 shows the absorption spectra of six degassed oil samples from the Middle East with different amounts of asphaltene content.

6 is a graph of an OD log as a function of wave number for the same six oil samples of FIG. 5.

FIG. 7 is a graph of the correlation between AIP (Absorption Capture Parameter) and total fluorescence intensity (TFI) for the six oil samples identified in FIG. 5.

Fig. 8 graphically shows the correlation between AIP and total TFI and% by weight of asphaltene for six different oil samples identified in Fig. 5.

Figure 9 shows the absorption spectra for the same six oil samples from the Middle East of figure 5 after adding 3% aqueous emulsion.

FIG. 10 compares the fluorescence intensity with (solid lines) and without (dashed lines) a 3% water / oil emulsion for the same six oil samples of FIG. 9.

11 compares the sensitivity of fluorescence as a function of the relative amount of water for different wavelengths and particle size distribution of the droplets.

Throughout the drawings, identical reference numbers indicate similar, but not necessarily identical, elements. Although the principles described in the materials of this application are susceptible to various modifications and alternative forms, individual embodiments have been shown in the drawings as an example and will be described in detail in the materials of this application. However, it should be understood that the invention is not intended to be limited to the particular forms disclosed. More specifically, the invention includes all modifications, equivalents and alternatives falling within the scope of the attached claims.

DETAILED DESCRIPTION

Illustrative embodiments and aspects of the invention are described below. Of course, it will be appreciated that when developing any such feasible implementation option, numerous implementation-specific decisions must be made to achieve the special goals of the developers, such as compatibility with system-related and business-related constraints that will vary from one implementation to another. . Moreover, it will be appreciated that such developments may be complex and time-consuming, but still could be commonplace for ordinary specialists in the art having the ability to understand the advantages of this disclosure.

The reference throughout the description of the invention to “one embodiment”, “embodiment”, “some embodiments”, “one aspect”, “aspect” or “some aspects” means that a particular feature, design, method or characteristic, described in connection with an embodiment or aspect are included in at least one embodiment of the present invention. Thus, the appearance of the phrases “in one embodiment”, or “in an embodiment”, or “in some embodiments” in various places throughout the description of the invention is not necessarily always indicative of the same embodiment. Moreover, specific features, structures, methods or characteristics may be combined in any suitable manner in one or more embodiments. The words “including” and “possessing” will have the same meaning as the word “comprising”.

Moreover, aspects having the features of the invention are contained in less than all the features of a single disclosed embodiment. Thus, the claims accompanying the detailed description are hereby expressly included in this detailed description, each claim being dependent on its own as a separate embodiment of the invention.

One of the advantages of Schlumberger's Compound Fluid Analyzer (CFA ™) is its ability to detect the gradients of the composite fluid within the oil column. Composition gradients can occur due to a variety of reasons: biochemical decomposition, gravity, temperature and / or diffusion gradients - all can contribute. Fluid gradients can also exhibit concentrated inhomogeneities, signaling the presence of cavities in reservoirs that were previously assumed to be homogeneous, the main reason for the lack of production capacity in the oil industry today.

In light oil samples, compositional gradients are mainly detected by changes in the GOR ratio. In heavy oil samples, GOR changes are less significant and compositional gradients are detected by differences in the location of the absorption boundary (i.e. color). Columns of heavy oil are known to undergo biochemical decomposition due to the fact that samples of heavy oil occur as a result of low-temperature catagenesis, and the bacteria of biochemical decomposition survive well at low temperatures. Despite this notable change in composition, practical difficulties in taking heavy oil samples in water-based drilling fluids prevent proper analysis of heavy oil samples in the column.

Problems arise because heavy oil samples are usually drilled using water-based drilling fluids that form stable water / oil emulsions due to activity at the interface between polymers and asphaltenes. Emulsions have an even higher viscosity than the naturally high viscosity of the original heavy oil. To aggravate cases, the flow of heavy oil emulsion through a porous medium exacerbates the problem caused by the active blockage of the neck according to the tension at the interface. Consequently, flooding water preferably passes, and the oil entering the fluid analysis or sampling tool slows down, resulting in longer cleaning times.

Emulsions affect optical measurements, since absorption spectroscopy (Bouguer-Lambert-Beer law) is highly sensitive to the presence of water droplets and particles in the flow line. The scattering intensity rises rapidly with increasing relative amount of water and, as a rule, depends on the wavelength. The negative effect is amplified in the forward direction to the detector. Since color removal is important for GOR and composition analysis, emulsions compromise the accuracy of both measurements, LFA ™ (real-fluid analyzer) and Schlumberger CFA ™. Even for relatively small relative amounts of water, it is difficult to correct for noise created by scattering in the absorption spectra.

One aspect described herein utilizes a correlation between the color of reservoir samples or fluids such as crude oil (absorption) and the fluorescence of a reference fluid. Some aspects, however, may use the fluorescence parameters alone or in combination with other data. The color characteristics of samples, such as crude oil samples, are known to those of ordinary skill in the art with the ability to understand the benefits of this disclosure. However, in emulsified samples of heavy oil, light scattering causes a deterioration in S / N (signal to noise ratio), so that the color of the crude oil cannot be accurately determined from the absorption spectra. Thus, there is a need for more reliable technology for characterizing fluids and / or detecting compositional gradients in emulsified heavy oil columns. Accordingly, one aspect describes a method of using FDUs (eg, FDUs from CFA ™ or any comparable optical fluorescence device) to collect a fluorescence signal or fluorescence parameters in a well. Fluorescence measurements can be made inside the tool (device) above the formation fluids instead of irradiating the walls of the wellbore. For example, a Schlumberger MDT device may be used and / or modified to collect or retrieve formation sample fluids for fluorescence analysis (and possibly another analysis, such as color analysis).

The color of crude oil occurs due to the absorption of photons by polycyclic aromatic hydrocarbons (RAS). An excited RAS can fade back to the ground state, either by re-emitting a photon at a longer wavelength (fluorescence) through non-radiative relaxation (thermal vibrations), or by transferring collision energy (kinetics). Thus, fluorescence is closely related to absorption, and the fluorescence intensity is considered correlated with the color of the crude oil. Since oil color can be used to detect fluid gradients and fluid cavities in heavy oil samples, fluorescence can be used as an alternative to detect changes in composition or identification or to obtain other characteristics of reservoir fluids in the well. However, the correlation between fluorescence and oil color is not trivial. For example, an increase in the chromophore concentration in oil results in an increase in color, but a decrease in fluorescence. That is, an increase in the concentration of the fluorophore of the crude oil reduces the fluorescence. This difficult to understand effect occurs largely due to intermolecular fluorescence quenching interactions due to the formation of diffusion and aggregation of the formation.

Generally speaking, detailed information about the composition and / or concentration cannot be determined only by the color of the oil, but relative changes in the concentrations of heavy fractions (for example, asphaltenes) cause large changes in color and associated fluorescence. Therefore, in some conditions, it is possible to correlate changes in the color of crude oil (or fluorescence) with changes in composition and / or concentration. It is also possible to compare the fluorescence data in the well with the fluorescence data of a known sample from laboratory analysis, provided that accurate calibration of the device in the laboratory is performed in advance.

Even after the downhole fluid analysis or sampling device is positioned in the wellbore, cleaning the selected flow line, performing accurate optical transmission measurements, and acquiring the sample can take up to fifteen hours to pump out. The long response time interferes with everything except the most rudimentary estimate of the composition change in a column of heavy oil drilled using water-based drilling fluids. However, for the purposes of DFA (downhole fluid analysis), they often do not need a sample, but only an analysis. Fluorescence requires only an oil film on a research optical cuvette or window. Oil films find their way into optical cuvettes or windows at the beginning, at the stage of cleaning the flow line, making fluorescence measurement and analysis an attractive data measurement.

Collecting a fluorescence signal using surface geometry is useful for several reasons. Samples of heavy oil are opaque at the wavelengths of the visible spectrum and for some geometry of the front surface, and the effects of self-absorption are minimized. In addition, the relatively short depth of fluorescence photon output in heavy oil samples ensures that the fluorescence measurement will be less disturbed by light scattering than the corresponding absorption measurement.

The long-wave absorption limit for most samples of crude oil is a consequence of polycyclic aromatic hydrocarbons (RAS). Coloration is linearly dependent on the concentration of these chromophores in accordance with the Birza law.

where: A is the absorption,

I _o - the intensity of the incident light,

I is the intensity of transmitted light,

ε _i is the molar absorption coefficient for component i and

c _i is the concentration of component i, and l is the mean free path.

In crude oil samples, quenching rate constants are limited by diffusion. The Stern-Volmer equation is obtained from an analysis of the decay rate in an excited state:

where: k _F is the attenuation rate in the excited state and the attenuation rate of the measured fluorescence,

k _Fo is the attenuation rate of intrinsic fluorescence in the absence of a quencher,

[Q] is the concentration of the quencher and

k _Q is the diffusion quenching rate constant.

(каковое применяется для образцов сырой нефти) интенсивность флуоресценции для концентрированного образца является пропорциональной концентрации гасителя. Гасителями являются крупные РАН, которые имеют сдвинутые в красную область электронные переходы, то есть одинаковые молекулярные доли, которые вызывают окрашенность сырой нефти.Equation 2 shows that for

(which is used for crude oil samples) the fluorescence intensity for a concentrated sample is proportional to the concentration of the quencher. The quenchers are large RASs that have electronic transitions shifted to the red region, that is, identical molecular fractions that cause staining of crude oil.

It can be shown that up to zero order, both colorings of crude oil (equation 1) and the fluorescence intensity of crude oil (equation 2) are linearly dependent on the chromophore filling of large RAS. Thus, for solutions of a given crude oil, color and fluorescence intensity can be quantitatively related.

Quantum returns of crude oil are higher at UV excitation wavelengths (e.g., 350 nm) than visible wavelengths (e.g. 450 nm). In addition, larger differences in the fluorescence spectra of crude oil samples are observed at shorter excitation wavelengths. Moreover, photons in the UV region have a shorter depth of exit than photons in the visible spectrum, which means that the fluorescence spectra are less disturbed by emulsions. Therefore, one embodiment of the present invention uses one or more UV LEDs or laser diode sources in a well on a fluid analysis device (for example, instead of blue). The UV light source can be modified on a fluid analysis device or presented as original equipment. However, one skilled in the art will readily understand that any excitation wavelengths can be used according to the principles described in the materials of this application. In view of this, the present invention is not intended to be limited by the embodiments set forth herein.

Figure 1 schematically illustrates one embodiment of a downhole analysis, sampling and fluid testing device in a wellbore. In the embodiment of FIG. 1, the device comprises a packer module 17 and a flow line 18. The flow line 18 extends through the device substantially in the longitudinal direction to the pump down module 13 at the first or upper end. The probe module 16 facilitates fluid transfer between the adjacent formation and flow line 18. Spectroscopy module (and / or FDU) 15 can be connected in series to flow line 18 (see FIG. 2). Sampling chambers 14 may be connected to flow line 18 and (if included) may receive and store fluid samples from the formation.

Figure 2 is a schematic representation of a CFA ™ absorption spectrometer 15 and an FDU 20. The FDU 20 may comprise a light source 22, and the light source 22 may comprise an LED or laser generating light, for example, at a wavelength of approximately 470 nm. FDU 20 includes one or more fluorescence detectors, such as first and second detectors 24, 26. The first and second detectors 24, 26 may contain silicon (Si) photodiodes and may include two long-pass optical filters that transmit light, for example , in excess of about 550 nm and 650 nm. However, those of ordinary skill in the art having the ability to understand the advantages of this disclosure will understand that the principles described herein are not limited to these particular devices or specific wavelengths considered. There may be any number of different embodiments of the FDU 20. For example, in yet another embodiment, multiple light sources with different wavelengths and multiple detectors are possible. The device of FIG. 2 can be implemented with any fluid analysis device, such as the device shown in FIG.

Figure 3 shows the effect of a water / oil emulsion on the absorption spectra of heavy oil from a geographic area in the Middle East. First line 28 shows the net absorption spectra of heavy oil from a geographic area in the Middle East. Additional lines illustrate the absorption spectra with increasing fractions of water. The scattering of light from water droplets (several microns in diameter) rises with increasing relative amount of water. Peaks 30, 32, etc. at 1725 and 1760 nm correspond to vibrational molecules of hydrocarbons. Water has vibrational bands at 1445 and 2000 nm.

Figure 4 shows the fluorescence spectra for the same heavy oil, figure 3, with the same fractions of water. The first line 34 shows the net absorption spectra of heavy oil from a geographic area in the Middle East. The remaining lines show spectra with increasing fractions of water. Compared to the absorption spectra shown in FIG. 3, the fluorescence spectra of FIG. 4 are much less sensitive to the content of the emulsion or water in the sample.

The fluorescence signals, which are illustrated in the present invention, are less sensitive to emulsion. In one aspect, this fluorescence insensitivity to emulsions is applied (instead of optical density) and is used to display color gradients in an oil column that reflect composition changes. These color gradients (for example, those that result from changes in composition), in turn, may be correlated with other physical properties of the oil, such as asphaltene content.

Figure 5 shows the absorption spectra of six degassed oil samples from the Middle East with different amounts of asphaltene content. From left to right, the relative amount of asphaltene increases from 3 to 13%. Vibration overtone bands are centered at 1725 nm. The location of the electronic absorption boundary reflects the distribution of the totality of aromatic components in crude oil. A graphical representation of the OD (optical density) logs versus wavelength (FIG. 6) shows that the slope of the absorption boundary is the same for all six crude oil samples. Approximating the electron absorption boundary by a linear equation of the form:

logOD = logα + β / λ

you can get a single number that characterizes the relative color change over the entire data set. This is indicated by reference as an absorption interception parameter (AIP).

7 is a graph of the correlation between AIP (absorption interception parameter) and total fluorescence intensity (TFI) for the six oil samples identified above. The correlation is:

AIP = -1.0905TFI-1,0557

R ² = 0.99

Thus, a single parameter (AIP) characterizing the color of the oil is in strict correlation with a single parameter characterizing the frequency response of fluorescence (TFI). Accordingly, in some embodiments, absorption and fluorescence can be used interchangeably as an indicator of relative fluid coloration.

Fig. 8 graphically shows the correlation between AIP and total fluorescence intensity (TFI) and% by weight of asphaltene for these six different oil samples. For AIP, the correlation is:

AIP = 0.0682 ·% by weight of asphaltene - 2.0957

R ² = 0.9

For fluorescence correlation is:

TFI = -0.0616% by weight of asphaltene + 0.9476

R ² = 0.952

Thus, both AIP and TFI are sensitive to changes in composition. These correlations are expected to increase when data is limited to a single reservoir. It is also expected that these correlations will further improve when data is limited to a single borehole. Other correlations may be detected by those skilled in the art having the ability to understand the benefits of this disclosure, in the usual experimentation, to the following principles described herein, such as between TFI and C36 + weight fraction, TFI and density, TFI and composition, TFI and viscosity.

Fluorescence logs can be obtained either by logging a well as a whole in quasi-continuous mode without collecting samples, or they could be logged when the operator decides that the fluid has changed composition. For example, the operator can compare fluorescence logs at locations A and B. If the fluorescence logs are identical, then the device moves to a new location C and the test is repeated. On the other hand, if the fluorescence signal has increased or decreased, then the operator can decide whether to capture a sample based on this knowledge of the information. The operator can correlate changes in the fluorescence frequency response with other logs to improve interpretation. Using a calibrated database for an individual reservoir, the operator can further associate fluorescence logs with changes in composition, density, viscosity and other physical properties.

Figure 9 shows the absorption spectra for the same six samples of oil from the Middle East, identified above, after adding 3% aqueous emulsion. Water droplets (approximately 1 micron in size) create intense scattering, which significantly distorts the absorption spectrum and reproduces the opacity of the sample with the resulting loss of information content. Scatter background and water peaks cannot reliably deviate to reveal the true color of the oil.

Figure 10 compares the fluorescence intensity with (solid lines) and without (dashed lines) 3% water / oil emulsion. The fluorescence signal shows a slight increase, but which contributes to the bias and does not affect the relative fluorescence intensities, but leaves the line shape unchanged. Water does not fluoresce at the wavelengths of the visible spectrum, and fluorescence photons that avoid self-absorption also experience slight scattering on the geometry of the front surface. Thus, fluorescence can be used to accurately display changes in composition, even when emulsions are present. Therefore, for ordinary specialists in the art having the ability to understand the advantages of this disclosure, it is possible to detect color (and composition), gradients, or other characteristics in an oil column in the presence of emulsions by using fluorescence logs.

11 compares the sensitivity of fluorescence as a function of the fraction of water for different wavelengths and particle size distribution of the droplets. Large droplets cause less dispersion than small ones. A shorter excitation wavelength in the UV region results in less scattering than wavelength radiation in the blue region.

As mentioned above, Schlumberger CFA ™ contains a fluorescence sensor that can perform fluorescence spectroscopy by measuring light emission in the green and red spectral ranges after excitation with blue light. Fluorescence in this range refers to the concentration of polycyclic aromatic hydrocarbons (RAS) in crude oil. Fluorescence was initially introduced to detect phase transitions, in particular, in gas condensate systems during sampling. When a phase transition occurs in the retrograde condensate fluid, the newly formed liquid phase will concentrate the heaviest components of the feed fluid. As mentioned earlier, these heavy components contain molecular groups that fluoresce. Fluorescence measurements are highly sensitive — in this case even more than other types of spectroscopy, such as absorption spectroscopy — and therefore make it possible to detect the smallest changes in the composition of the analyzed fluid.

Based on the above measurement principles and extensive observations, some signs of CFA ™ fluorescence follow from infield practice:

- Fluorescence does not suffer from strong scattering, usually caused by solid particles in the drilling fluid. It is very likely that the solids in the drilling fluid do not contain any RAS.

- Fluorescence measurements in the wellbore are less affected by water droplets in oil-in-water emulsions than the corresponding absorption measurements. This feature provides the ability to identify the properties of oil, even when emulsions of oil and water are present.

- Fluorescence can be used to typify various hydrocarbons, such as gas (it should be noted that the gas is a fluid), condensate, light oil and oil residue. In simple words, gases usually contain little or no heavy components, hence very little RAS. Therefore, the gas must have very weak fluorescence. Oil typically contains more heavy components, hence much more RAS. Accordingly, oil samples should have stronger fluorescence than gases.

- Fluorescence is highly sensitive. Therefore, it can detect very small oil droplets mixed with water.

“Moreover, fluorescence will not respond to OBM (oil-based drilling fluid), since OBM typically should not contain any RAS.

The foregoing description has been presented only to illustrate and describe some embodiments. It is not intended to exhaustively or limit the invention of any exact form disclosed. Many modifications and variations are possible in light of the above description.

Embodiments and aspects were selected and described in order to best explain the principles of the invention and its practical application. The preceding description is intended to provide an opportunity to others skilled in the art to best use the principles in various embodiments and aspects and with various modifications that are suitable for the intended practical use.

Claims (29)

1. A method of analyzing fluid properties, comprising the steps of
(a) providing a downhole fluid analysis device, wherein the downhole fluid analysis device has means for receiving a fluorescence signal;
(b) recovering the fluid from the wellbore using the downhole fluid analysis device so that the extracted fluid enters the downhole fluid analysis device; and
(c) using a fluorescence signal acquiring means to collect a fluorescence signal from the extracted fluid while in the well to analyze fluid properties. 2. The method of analyzing fluid properties according to claim 1, wherein collecting the fluorescence signal by means of obtaining a fluorescence signal comprises irradiating the extracted fluid through an optical cuvette and then detecting fluorescence. 3. The method of analyzing fluid properties according to claim 1, further comprising
repeating steps (b) and (c) at multiple locations along the wellbore so as to obtain at least one fluorescence signal for each location from said multiple locations. 4. The method of analyzing fluid properties according to claim 3, further comprising identifying fluid composition gradients in the fluid column by comparing two or more received fluorescence signals associated with a corresponding location from the plurality of locations along the wellbore. 5. The method of analyzing fluid properties according to claim 3, further comprising:
form a quasi-continuous log of the resulting fluid without collecting samples in the downhole fluid analysis device. 6. The method for analyzing fluid properties according to claim 1, further comprising
comparing the obtained fluorescence signal with known fluorescence spectra;
identify the obtained fluid based on a comparison of the received fluorescence signal from the obtained fluid with known fluorescence spectra. 7. The method for analyzing fluid properties according to claim 1, further comprising
comparing the obtained fluorescence signal with known spectra while in the well;
identify the obtained fluid based on a comparison of the received fluorescence signal from the obtained fluid with known fluorescence spectra while in the well. 8. The method of analyzing fluid properties according to claim 1, further comprising
correlate the obtained fluorescence signal and other physical characteristics of the obtained fluid to form at least one data point. 9. The method of analyzing fluid properties of claim 8, wherein the other physical characteristics comprise one or more of: density, viscosity, and C36 +. 10. The method of analyzing fluid properties according to claim 1, further comprising: correlating the obtained fluorescence signal with other log data or log data while drilling so as to facilitate interpretation of the obtained fluorescence signal to analyze the fluid property and other physical properties fluid. 11. The method of analyzing fluid properties according to claim 1, further comprising correlating the obtained fluorescence signal with other logging or logging while drilling and identifying the relationship between the obtained fluorescence signal and the logging data or logging data while drilling. 12. The method of analyzing fluid properties according to claim 1, further comprising correlating the obtained fluorescence signal with other logging or logging data while drilling and creating models or tables to assist in interpreting the obtained fluorescence signal. 13. The method of analyzing the properties of the fluid by identifying gradients of the composition of the fluid in the oil column, which consists in the fact that
moving the fluid analysis device along the wellbore;
fixing a fluid analysis device at a desired sampling interval;
extracting fluid from the formation adjacent to the wellbore into a flow line in the housing of the fluid analysis device;
irradiating the fluid in the flow line through an optical cuvette inserted in the flow line;
detect fluorescence, and the above-mentioned obtained from the detection of fluorescence is used to identify gradients of the composition of the fluid. 14. The method of analyzing fluid properties according to item 13, further comprising identifying gradients of the fluid composition in the fluid column by comparing fluorescence signals along the sampling interval. 15. The method of analyzing the properties of the fluid according to item 13, further consisting in the fact that
comparing the fluorescence obtained as a result of detection with known fluorescence spectra;
fluid is identified based on a comparison of the detected fluorescence with known fluorescence spectra. 16. The method of analyzing fluid properties according to item 13, in which the distance between fixations on the sampling interval is regular or irregular. 17. The method of analyzing the properties of the fluid according to item 13, in which the irradiation is performed by light with a wavelength of the UV region. 18. The method of analysis of the properties of the fluid from the reservoir sample, which consists in the fact that
collect fluorescence data from the reservoir sample while in the well in numerous places;
analyze changes in fluorescence in two or more of the many places; and
comparing said analyzed changes in fluorescence in two or more of the many places. 19. The method of analyzing fluid properties according to claim 18, further comprising
measure the color of the reservoir sample in numerous places;
associate changes in fluorescence parameters with changes in fluid color. 20. The method of analyzing fluid properties according to claim 18, further comprising using changes in fluorescence parameters to determine if there are fluid cavities within the formation. 21. The method of analyzing the properties of the fluid according to p, further consisting in the fact that
analyze the structure of fluorescence data over an extended interval of depths;
form an indication of the physical property correlated with fluorescence in such a way as to facilitate the interpretation of the fluorescence signal to analyze the fluid property and other physical characteristics of the fluid property. 22. The method of analyzing fluid properties according to claim 18, further comprising the steps of
correlate fluorescence data with other log data;
identify the relationship between fluorescence data with other log data;
create one or more models of well logs. 23. The method of analyzing fluid properties according to claim 18, wherein the fluorescence data can form a quasi-continuous well log. 24. The method of analyzing fluid properties according to claim 18, wherein the reservoir sample contains an aqueous / oil emulsion. 25. A device for analyzing fluid properties, containing
a downhole fluid analysis device, wherein the downhole fluid analysis device comprises
a fluid recovery module having at least one flow line;
an optical cuvette interacting with at least one of the flow lines;
a radiation source located next to the optical cell;
a fluorescence detection unit located next to an optical cell. 26. The device according A.25, further comprising a fluid color control module. 27. The device according A.25, in which the radiation source contains an LED or laser diode, made with the possibility of the formation of visible, ultraviolet or infrared light. 28. A method for analyzing fluid properties, which comprises providing an existing downhole fluid analysis device and combining a fluorescence detection unit with an existing downhole fluid analysis device in such a way as to facilitate fluid property analysis. 29. The method of claim 28, further comprising combining the downhole fluid analysis device with a UV light source.

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