CN101498215B - Enhanced downhole fluid analysis - Google Patents

Abstract

The operation, the analysis and the explanation of a chromatogram system can be obviously reinforced by coupling the chromatogram system with property measurement of one or a plurality of fluids. The property measurement of fluids provides fluid kinds, the existence of any pollutant, the estimation of hydrocarbon composition (C1, C2-C5 and C6+), the ratio of gas and oil, and the primary indication of color and/or fluorescent measurement. The other measurement used for the primary stage can include the measurement of density, viscosity and phase change. The measurement can be used for reinforcing the sampling regulation and the analysis regulation of GC in real time, and simultaneously improving the stability of chromatogram explanation.

Description

Enhanced Downhole Fluid Analysis

technical field

The present invention relates to formation fluid analysis, and more particularly to systems and methods for enhanced chromatographic analysis of downhole fluids, such as borehole fluids, using initial characterization of properties of the fluids, followed by further analysis Fluids, Treatment Fluids, Formation Fluids and Drilling Muds. the

Background technique

Chromatography is a technique commonly used in surface-based facilities to characterize subsurface-produced hydrocarbons. It provides high-resolution composition analysis for long-chain hydrocarbon compounds, including, for example, hydrocarbon compounds above C36+. These techniques can be used for equation of state adjustment and subsequent compositional model simulation of fluids in a reservoir to facilitate or inform planning and design of reservoir production strategies and surface-based production facilities. the

In surface-based laboratories, formation hydrocarbon samples are typically flashed to ambient conditions to separate dissolved gas and liquid hydrocarbon phases. Any water that may be present in the collected liquid hydrocarbon (oil) phase is separated. Not only can the injection of an oil-water mixture interfere with quantitative hydrocarbon analysis, but contact with water can cause rapid degradation of the stationary phase in the column. Standard analytical protocols, including column type and configuration, temperature program, carrier gas flow and pressure, injector and detector temperatures, were used for characterization. One or more chromatographic systems and procedures can be used for the analysis of gaseous and liquid hydrocarbon phase fractions to maximize resolution and precision. Typical analysis times for this standardized technique range from a few minutes to an hour. the

To obtain formation fluids, a formation tester tool with a sampling probe, pump assembly, and flowline is typically used. Typically, a sampling probe contacts the formation and a pump is used to draw fluid from the formation to a flowline, which may contain one or more sensor trains for in situ analysis. The fluid can then be either disposed of into the wellbore or collected in sample vials for further surface-based analysis. The fluid can be a single phase or a multiphase mixture of water and gas/liquid hydrocarbons. The initial fluid drawn into the tool is usually highly contaminated with drilling mud filtrate. The filtrate may be water-based (immiscible with formation hydrocarbons) or oil-based (miscible with formation hydrocarbons). By pumping continuously for a long time, the contamination drops and the fluid becomes more representative of the true formation fluid. the

Pilkington in US Patent 4,739,654 discloses a method and apparatus for downhole chromatography of a single-phase flow using a chromatography system. In Pilkington's technique, resistivity sensors are used to identify hydrocarbon samples that are not highly contaminated with oil-based mud filtrate. However, Pilkington fails to address the use of alternative sensors, such as optical sensors, to track oil-based mud contaminants. Also, Pilkington failed to point out the difference between formation water (or water-based mud filtrate) and oil. the

If only chromatographic systems were used in a downhole environment, sampling would be blind without prior knowledge of fluid species such as water, gas, and/or liquid hydrocarbons or pollutants. Sampling of water and injection into the chromatographic system should be avoided as it is not relevant for pressure-volume-temperature (PVT) characterization of hydrocarbons. Exposure to water may cause rapid degradation of the column stationary phase and/or interfere with quantitative hydrocarbon analysis. Another problem with blind sampling is that when the hydrocarbon fluid is a mixture of gaseous and liquid phases, it is difficult to sample both phases in representative fractions to obtain accurate quantification. In order to maintain the integrity of the analysis, it is preferred to sample the two phases separately by single-phase injection and obtain their compositions independently. the

In addition, it is important to know the percent contamination, especially when samples contain miscible oil-based mud filtrates, since high contamination drastically changes the properties of formation fluids, so compositional analysis of such samples is of no value. Acceptable contamination levels in formation fluid samples are about 5% or less for oil-based mud filtrates. In the case of water-based mud filtrates, it is important to separate the hydrocarbons prior to analysis. Therefore, it is advantageous to perform fluid property characterization and chromatographic analysis only when contamination levels are below acceptable levels to obtain results for equation of state (EOS) adjustment and estimation of fluid properties. Although chromatography is commonly used in surface laboratories to estimate contamination, repeated sampling by chromatography over extended periods of time under downhole conditions is ineffective in tracking contamination. This not only increases the consumption of limited resources such as carrier gas on the downhole tool, but also causes a decrease in chromatographic performance. Most columns are reconditioned after a certain number of injections. It would be advantageous to use only chromatography for sample analysis if more efficient methods were available for contamination tracking. the

A wellbore typically penetrates several formations filled with various types of fluids ranging from dry gas to heavy oil. Therefore, downhole tools should preferably be capable of analyzing various fluids in a single logging run. Without a priori knowledge of the hydrocarbon sample species, for example standard procedures will have to be used regardless of whether it is a dry gas with a composition mainly to C7, or a black oil with a composition all the way to C36 and higher. Therefore it is not possible to adjust and optimize according to the sample type to improve resolution and precision. This may also result in unnecessarily longer analysis times. Long wait times at analysis stations not only result in higher costs related to drilling time, but also increase the risk of tools getting stuck in the wellbore. Longer analysis times also mean an increase in consumables such as carrier gas, which is an important consideration in downhole environments because only a limited supply exists. the

An aspect of the present invention addresses these deficiencies in the prior art. the

Contents of the invention

According to some aspects, the present invention relates to an analytical system comprising a first platform configured to receive at least a portion of an analyte and provide an indication of at least one property of the fluid, and a second characterization platform. A characterization platform is configured to receive at least a portion of the formation fluid and includes at least one chromatographic linkage. The term "chromatographic linkage", "analytical linkage" or "coupling" as used herein may include one or more samplers/injectors, one or more columns and one or more detectors, which are fluidly connected to A relevant characterization of the eluate from the column or columns is provided. Additionally, for clarity, the term "analyte" is used herein to refer to the fluid sample being analyzed. According to the present invention, the analyte may be single-phase or multi-phase, and may comprise a liquid hydrocarbon phase, an aqueous phase or a gaseous hydrocarbon phase. the

According to one or more aspects, the invention relates to a method of characterizing an analyte. The method may include one or more of the following acts: determining in a first characterization platform at least one first property of the analyte, and based at least in part on said at least one first property, in a second characterization platform The composition of at least a portion of the analyte is determined. the

Description of drawings

In the accompanying drawings, Figure 1 illustrates a flow chart according to one or more embodiments of the present invention;

Figure 2 is a graph showing the optical density of various oils as a function of wavelength;

Figure 3 is a graph showing the absorption spectra of an oil sample and a water sample;

Figure 4 is a graph showing contamination predictions for oil samples using a Live Fluid Analyzer on a formation tester;

Figure 5 is a diagram illustrating detection of multiple phases downstream of a pump out assembly using a Composition Fluid Analyzer on a formation tester; and

Figure 6 is a graph showing downhole fluid analysis logs from an oil zone using a constituent fluid analyzer on a formation tester. the

Detailed ways

The present invention provides systems and techniques for downhole, in situ, formation fluid characterization. Aspects of the invention provide systems and techniques that facilitate chromatographic characterization of formation fluids. Facilitating the characterization of such formation fluids in a downhole environment may include initially determining at least one or more properties of the formation fluids, such as optical signature, fluid type, fluid density, fluid color, fluid fluorescence gas-oil ratio, and low resolution rate composition. Accordingly, some aspects of the invention relate to hierarchical or staged characterization systems and techniques in which a first analysis step or platform may be utilized with one or more further analysis platforms to characterize formation fluid properties. The first characterization platform may include a non-destructive platform, including, for example, techniques that measure intrinsic properties of the fluid being analyzed. The fluid may be a formation fluid, and the intrinsic property may be at least one fluid property of a formation fluid component. Those skilled in the art will recognize that a variety of alternative fluids may be used in the practice of the present invention. Additionally, for purposes of illustration, the present disclosure will be described with respect to fluids encountered in a downhole environment, referred to herein as "formation fluids." Such descriptions are not intended to limit the scope, as the invention may be practiced on a variety of alternative fluids, as will be appreciated by those skilled in the art. The first or initial characterization function may facilitate or accelerate characterization of the formation fluid, or at least a portion of the formation fluid. However, if, for example, the first platform characterization is performed in a bypass mechanism, it is also possible to utilize the first platform performing a destructive characterization of a portion of the sample to provide the initial characterization. the

Further features of the invention relate to downhole analysis that includes rapid and efficient characterization while achieving the desired chromatographic separation. For example, the present invention may allow selection of an optimal chromatographic separation protocol based on knowledge of the fluid species. However, in the absence of prior knowledge of the fluid, a single protocol will be used to ensure proper characterization. This may unnecessarily extend the analysis cycle or require unnecessarily complex procedures. For example, if the sample contains mostly dry gas, unnecessarily long analysis times and temperature ramps will be employed to reach high column temperatures that primarily target higher carbon number components that are not present. This may also result in a longer cooling time for the system before the next analysis. the

In order to use the gas chromatographic output for EOS adjustment, the mass or mole fraction of all components in the sample fluid should be known. In ground-based laboratories, chromatographic quantification in terms of mole or mass fractions requires accounting for components that are present in the sample but not in the chromatographic output. This may be because: (i) they are too strongly adsorbed to the stationary phase and never elute during the analysis time, (ii) they never elute in the sampler due to low volatility under the temperature and pressure conditions employed. / evaporated in the syringe, so that the part of the sample plug that did not evaporate is injected into the column, or (iii) they are backflushed and thus do not pass through the detector. In ground-based analyses, these components are typically specified by the use of internal standards (specific components mixed with the sample in precisely measured proportions), as in the methods described in ASTM D5307-97 and D5442-93. However, very precise mixing of internal standards and hydrocarbon samples in downhole gas chromatography tools can be intricate. the

Aspects of the invention may include a downhole tool or system comprising one or more initial characterization systems, subsystems or components that provide initial values and properties of fluids. The present invention advantageously integrates chromatography systems and techniques with other sensors and/or procedures, such as those based on optical techniques, resistivity, NMR, and/or provide measurements of intrinsic properties, such as density and/or viscosity. the

Figure 1 schematically illustrates one embodiment of the present invention. Optical-based subsystems can initially determine the presence of any aqueous or gaseous or liquid (oil) hydrocarbon phases in the analyte. Thus, the presence or absence of water, oil and/or gas can be initially characterized in a first characterization step 112 . In some cases, further embodiments may provide an estimate of any dissolved gas-to-oil (GOR) ratio for at least an analyte. Some further aspects may include color and fluorescence characterization of at least a portion or component of an analyte, which may be further used in one or more subsequent or accompanying characterization linkages. For example, the color and/or fluorescence of the liquid hydrocarbon phase may be determined, and the determined initial or first property may provide a qualitative estimate of the properties of the oil, such as a light or heavy hydrocarbon oil. Absorption spectra in the visible to near-infrared region can be used for low-resolution compositional analysis, e.g., C1, C2-C5 or C6+, and any oil-based mud contamination, as described in: Andrews et al., "Using Crude Oil Quantifying Contamination Using Color of Crude and Condensate", Oilfield Review, Fall 2001, pp. 24-43, and Betancourt et al., "Analyzing Hydrocarbons in the Borehole," Oilfield Review, Fall 2003, pp. 54-61, which describe these optical measurements in more detail. Further characterizations may be evaluated at step 122, if appropriate. If a sample is considered to be contaminated or to consist primarily of undesired components, further characterization is not considered and another sample may be withdrawn, 122, no. Additionally, another sample may be withdrawn if the initial or first characterization results are inconclusive, ambiguous, and/or otherwise invalid. This is shown at step 106 for purposes of illustration, however, those skilled in the art will recognize that retrieval of another sample may occur at various alternative platforms, including at steps 112 or 122 . For example, if the recovered analyte consists primarily of non-hydrocarbon components, the sample may be discarded and no further characterization will be performed. If the valid sample is worthy of further evaluation, 122, yes, in one or more second characterization steps 142 the sample is transferred to a second or subsequent analysis. In some cases, one or more optional steps of determining one or more parameters of second characterization step 132 may be performed based at least in part on first characterization results, eg, in one or more chromatographic linkages. Additional optional operations may include combining the first and second results 152 to provide enhanced interpretations regarding analyte quantities, characteristics and/or properties. the

In some embodiments of the invention, the hue and intensity of light transmitted or reflected by the sample can be used to distinguish oils of different compositions. Absorbed light or optical density (OD), which can be the ratio of incident light to transmitted light, can be used to provide characterization of the composition, with the darker the fluid, the higher the OD. For example, light hydrocarbons are typically colorless and do not absorb light in the visible spectrum, while condensates can be clear or slightly reddish-brown because they absorb blue light, and heavy crudes with complex molecules Typically dark brown because light is absorbed throughout the visible spectrum. Accordingly, in some embodiments of the invention, the first characterization platform includes measuring optical density to provide an initial characterization of the sample. In some cases, the feature under consideration may be the presence of one or more fluid phases. Optical system-based tools such as Schlumberger's Fresh Fluid Analyzer (LFA ^™ ) and Constituent Fluid Analyzer or CFA ^™ can also be used to detect single-phase and multiphase flows, and further information on suitable Sampling conditions or an indication of whether the returned sample should be further analyzed. In further embodiments of the invention, optical based systems as well as those measuring eg the resistivity or conductivity of fluids and those utilizing nuclear magnetic resonance (NMR) may also be used in the first characterization platform.

A particularly advantageous embodiment of the invention may employ spectroscopic measurements of a sample to provide an initial signature or signatures. In some special cases, a spectral signal from a sample can be captured, and specific constituents of the spectrum, e.g., light at selective wavelengths, can provide an indication of desired and/or undesired components in the sample or does not exist. Figures 2 and 3 (based on those contained in Andrews et al., "Quantifying Contamination Using Color of Crude and Condensate", Oilfield Review, Fall 2001, pp. 24-43 data), exemplarily showing a graph of the relationship between optical density and wavelength of light. As shown in Figure 3, water typically absorbs light at near-infrared wavelengths, ie, around 1445 and 1930 nanometers. Accordingly, optical techniques may be employed to determine the presence of water in a sample by capturing/observing a response or characteristic property of the sample to provide an indication of the presence and/or absence of one or more target considerations. the

In one embodiment of the invention, the optical system may comprise at least one light source, such as a light emitting diode, optically coupled to at least one refractometer, typically through a window, which may be a sapphire window. The window is typically a sapphire window positioned against or part of the flowline containing the fluid being characterized. Refractometers use reflected light from windows to quantitatively identify fluid phases in oil lines. At the chosen angle of incidence, the reflectance of gas in contact with the window is much greater than that of oil or water in contact with the window. In further embodiments, the optical system may further comprise a second light source and a detector assembly to determine the absorption characteristics of the fluid. One or more broadband light sources such as high temperature halogen tungsten lamps can transmit broad spectrum light through the fluid. Measure the distribution of transmitted light throughout the visible and near-infrared spectrum. Multiple channels can be used to selectively determine, observe, or quantify light in multiple wavelength ranges of the spectrum. Measurements from each channel provide an indication of the relative amount of the corresponding component in the sample. the

In addition, differentiation of particulate contaminants such as solid phase material in mud can be performed, since the presence of such contaminants is typically evidenced as noise in OD measurements. For example, Figure 4 shows a graph that can be used in optical methods to track contaminants in formation fluids from oil-based mud (OBM) filtrates. The Fresh Fluid Analyzer or LFA ^™ from Schramberger, substantially described by Andrew et al. in Oilfield Review, pp. 24-43, Fall 2001, can be used in real time. The OBM filtrate was colorless and had no dissolved methane. As pumping continues and contaminants drop in the sampled fluid, the fraction of formation fluid in the sample increases. This is evidenced by an increase in optical density in the color and methane wavelength channels that increases and stabilizes as pollution stabilizes. In the sampled example shown in the figure, the color channel data predicts about 4.9% pollution, while the methane channel predicts about 6.2% pollution. An average of 5.5% was consistent with 4.3% contamination determined by GC analysis of collected samples in the laboratory.

Figure 5 (based on data contained in Betancourt et al., SPE 87011, SPE Asia Pacific Conference, Kuala Lumpur, Malaysia, March 2004)) shows that the composition located downstream of the pump-out assembly in the formation tester tool can be Fluid analyzers perform optical measurements. Pumping out components causes gravity separation of the gas, oil and water phases. Optical signals from fluorescence and absorption measurements map the morphology of an oil-water-gas slug as it flows through an optical sensor in the flowline. This prior first characterization is potentially important in avoiding water sampling and selecting representative single-phase oil and gas samples for second analysis using chromatography linkages. the

Thus, in some aspects of the invention, the efficiency of downhole chromatography systems and techniques can be enhanced or improved by facilitating real-time evaluation of when to take samples. For example, an optical-based first characterization subsystem can ensure that gas chromatography (GC) analysis is performed only in the absence of water. In many mixed hydrocarbon-water streams, the pump assembly acts as a downhole separator and creates a slug of water and hydrocarbons. Using the first characterization tool as a guide can be used in sampling to capture hydrocarbon slugs. This will ensure relevant measurements and prevent damage to water-sensitive columns. Similar separations can occur in the presence of oil/gas streams. Thus, for example, an optics-based first system could be used to direct sampling timing to recover an oil sample and then a gas sample in the next run. the

The chromatographic train of the present invention typically includes one or more samplers/injectors, one or more columns, and one or more detectors fluidly connected to provide a correlated characterization of the eluate from the one or more columns . Typically, the detector may be, for example, a flame ionization detector or a thermal conductivity detector, and the column contains a stationary phase, e.g., a gel or other suitable Material. the

In one or more preferred embodiments, an optical-based system can rapidly and/or continuously facilitate determination of optimal GC sampling periods based on contamination. For example, samples are typically withdrawn only when contamination is low enough that sample analysis is useful. Although GC can be used to track contamination, it is preferable to reduce the number of GC analyzes since GC analyzes typically take longer than eg optical-based analysis techniques. In contrast, optical-based primary analysis can continuously monitor contamination and trigger additional characterization when contamination is deemed sufficiently low, eg, when GC analysis of the sample is appropriate. Avoiding or reducing the reliance on chromatographic characterization for contamination tracking can reduce the time tools spend at fluid sampling stations, since GC analysis typically takes longer than in situ optical analysis in the wellbore. This reduces the risk of tool jamming. An additional benefit of selectively sampling or classifying contamination prior to chromatographic characterization is that the consumption of carrier phase can be reduced. Thus, in some embodiments, a smaller complete system can be utilized because of the reduced operational requirements for performing similar quantitative and/or qualitative analyses. In addition, column degradation is minimized, allowing more relevant representative sample analysis before the column requires reconditioning. the

Methane and carbon dioxide can often co-elute. Optical characterization of methane component mole fractions allows determination of the relative amount of carbon dioxide by, for example, compensating the measured methane contribution by the measured combined methane and carbon dioxide determined by chromatography. Accordingly, some embodiments of the invention may avoid chromatographic methods, which are typically used to separate methane and carbon dioxide, methods that typically have longer analysis times. Therefore, some aspects of the present invention pertain to the combination of chromatographic analysis and optical analysis system for better quantification and interpretation. Optical analysis with CFA ^™ gives C1, C2-C5 and C6+, and these outputs can be used to check agreement with GC measurements. If there is a significant difference, it is detected in real time and an opportunity for repeated measurements is allowed.

Yet another feature of the invention may pertain to utilizing the first fluid property information to improve or even optimize chromatographic analysis. For example, a characterization system or tool may contain one or more stored analysis protocols including, for example, temperature programs, carrier gas flow rates, and/or pressure schedules. Depending on the type of hydrocarbon, eg, dry gas, light oil, heavy oil, etc., various protocols may be used, with the optimal and/or preferred analysis protocol typically selected in real-time to improve resolution and provide rapid analysis. the

In some embodiments of the invention, the density and/or viscosity of the analyte may be determined under downhole conditions, for example using vibration sensors, such as those disclosed in WO2002077613 and WO2006094694, to provide initial characterization. Viscosity information can be used to obtain qualitative information about hydrocarbon type, light or heavy. The color spectrum can be quantified more coarsely using density information. the

As explained before, not all sample components can be eluted into the chromatogram because of incomplete vaporization in the sample/injection cell or strong absorption on the stationary phase, etc. Current laboratory methods use an internal standard, as described in ASTM D5307-97 and D5442-93, to determine its mass lost in chromatography. This score is called the additional score and, together with the mass information of all other components, can provide the total fluid composition. This information can then be used to estimate the relationship between pressure, volume and temperature using EOS. Typically, the characteristic constants of the equation of state are adjusted using precise and detailed composition and measured fluid properties such as bubble point, dew point, phase miscibility with other components, compressibility, density, etc. (see, Ahmed( Ahmed) et al., SPE 15673). Under downhole conditions, it is difficult to prepare quantitative mixtures using internal standards and fluid samples. Typically, the use of, for example, a precision sample loop will allow the chromatographic sampler to extract precise volumes of fluid at downhole pressure and temperature. Recent publications, such as WO2002077613 and WO2006094694, disclose vibratory devices for measuring density with high precision under downhole conditions. Using the measured density and volume, the total mass of the sample for chromatographic analysis can be calculated. The peak areas of the eluted components in the chromatogram can be used to obtain the mass of each eluted component. The difference between the total eluted mass and the input mass is the lost mass. This makes it possible to determine the mass and additive fractions of eluted components and the overall composition of the fluid, which can then be used as input information for the EOS model. the

The systems and techniques of the present invention contemplate utilizing additional fluid sensors for downhole measurements, such as NMR as disclosed in (Lo et al., SPE 77264, SPE Journal, March 2002, pp. 24-34), For measuring hydrocarbon fluid viscosity and gas-oil ratio. Resistivity sensors can be used to differentiate between water and hydrocarbon fluids. Other sensors that measure fluid phase transition properties such as bubble point, dew point, wax appearance temperature, and asphaltene onset pressure can also provide information that can be combined with downhole gas chromatography analysis to further facilitate downhole EOS tuning, It also allows real-time consistency confirmation of all measurement sensors. the

Figure 6 shows the downhole pressure and fluid analysis logs from the well using the compositional fluid analyzer on the formation tester. These fluid analysis logs are based on data from Fujisawa et al., SPE 89704, SPE ATCE, Houston, Texas, September 2004). Pressure logs clearly show the presence of gas, oil and water zones in the formation. Fluid logs at the five sampling stations show large compositional variations in hydrocarbons, as seen in the C1, C2-C5 and C6+ fractions and the GOR in m3/m3 on the right. This change was confirmed by subsequent laboratory measurements. The upper station fluid (xx68.2m) with a high GOR is interpreted as being in the gas cap region and is a retrocondensate with a light color and about 34 wt% C6+. The lower station (xy06.3m) was determined to be a heavier black oil containing more aromatics and about 72 wt% C6+. Therefore, if chromatographic analysis is performed in this well, the same system must simultaneously analyze a gas sample at a shallow depth of about xx68.2m and a heavier black oil at a depth of about xy06.3m. A typical chromatographic protocol starts at low temperature to provide sufficient resolution in the lighter components and then ramps up the temperature to elute the heavier components. The analysis can be carried through to completion using a conditioning cycle and/or backflushing to remove non-eluting components. Chromatographic separation and analysis of gas samples can be achieved in a shorter time and with lower maximum temperatures to elute all components than the separation and analysis of heavier oils. Higher maximum temperatures for heavier oils through temperature ramping will also mean longer cooling times before starting subsequent analysis. It is also possible that heavier oils have greater lost mass and require post-analysis reconditioning cycles and/or backflushing to remove any uneluted components from the column. Existing knowledge from optical analysis helps to optimize chromatographic protocols, so that faster protocols can be used for gas samples if there is prior knowledge about the hydrocarbon species. Also note that this prior knowledge will avoid the chromatographic stand in the water band. the

While a few illustrative embodiments of the present invention have been described, it should be readily apparent to those skilled in the art that the foregoing has been presented by way of example only for purposes of illustration and not limitation. Various modifications and other implementations are within the purview of one of ordinary skill in the art and are considered to be within the scope of the invention. In particular, although many of the examples presented herein involve particular combinations of method acts or system elements, it should be understood that these acts and these elements may be combined in other ways to achieve the same ends. the

Those skilled in the art will appreciate that the parameters and configurations described herein are exemplary and that actual parameters and/or configurations will depend on the specific application for which the systems and techniques of the present invention are used. Those skilled in the art will also recognize, or be able to ascertain, using no more than routine experimentation, equivalents to specific embodiments of the invention. It is therefore to be understood that the embodiments described herein are presented by way of example only, and that within the scope of the appended claims and their equivalents; the invention may be practiced otherwise than as specifically described. the

Moreover, it should also be understood that the present invention relates to each feature, system, subsystem or technique described herein, and if such features, systems, subsystems and techniques are not mutually incompatible, any two or more features, systems, subsystems and techniques described herein Any combination of systems, subsystems or techniques, and any combination of two or more features, systems, subsystems and/or methods, is considered to be within the scope of the invention as embodied in the claims. Furthermore, acts, elements and characteristics discussed in connection with only one embodiment are not intended to be precluded from a similar role in other embodiments. the

As used herein, the term "plurality" refers to more than two items or components. The terms "comprising", "comprising", "with", "having", "containing" and "involving", whether in the written description or in the claims etc., are open-ended terms, that is, Means "including but not limited to". Accordingly, use of such terms is meant to include the items listed thereafter, and equivalents thereof, as well as additional items. Regarding the claims, only the transitional phrases "consisting of" and "consisting essentially of" are respectively closed or semi-closed transitional phrases. The use of ordinal terms such as "first," "second," "third," etc. in the claims to alter a claimed element does not by itself imply any priority, superiority, or a claimed element An order over another or a temporal order in which a method is performed, but is used only as a marker to distinguish a claimed element bearing a certain name from another element bearing the same name (but using sequential terms) to distinguish claimed elements of protection. the

Claims (19)

1. an analytical system, it comprises:

The first characterization platform, this platform is configured to the instruction of at least one character that receives analyte and this analyte is provided, wherein at least one character based on indicated and described analyte is defined as is effective analyte sample; With

The second characterization platform, this platform is configured to receive at least a portion analyte of described effective analyte sample and comprises at least one chromatography linkage.

2. analytical system claimed in claim 1, the first and second wherein said characterization platform are contained in shell.

3. analytical system claimed in claim 1, it also comprises controller, and this controller is operatively connected, and is sent to described the second characterization platform to receive from the signal of described the first characterization platform and by least one control signal.

4. analytical system claimed in claim 1, the first wherein said characterization platform comprises the detector based on optics, this detector is arranged to provide at least one the instruction in the fluid composition of type of fluid, pollutant level and at least a portion analyte.

5. the analytical system of claim 1, the first wherein said characterization platform comprises density sensor, this density sensor is arranged to provide at least one the instruction in the density of at least a portion analyte.

6. analytical system claimed in claim 1, wherein said analyte is formation fluid.

7. analytical system claimed in claim 6, wherein said formation fluid is heterogeneous fluid.

8. analytical system claimed in claim 7, wherein said formation fluid contains water.

9. analytical system claimed in claim 7, wherein said formation fluid contains gas hydrocarbon phase.

10. analytical system claimed in claim 7, wherein said formation fluid contains liquid hydrocarbon phase.

11. 1 kinds characterize the method for analyte, and the method comprises one or more following behaviors:

In the first characterization platform, provide analyte, so that the instruction of at least one the first character of described analyte to be provided, wherein at least one first character based on indicated and described analyte is defined as is effective analyte sample; With

At least one first character based on described at least in part, the composition of at least a portion analyte of definite described effective analyte sample in the second characterization platform.

Method described in 12. claims 11, the method is also included in the behavior of determining the hydrocarbon content of at least a portion analyte in described the first characterization platform.

Method described in 13. claims 12, the method also comprises that at least part of hydrocarbon content based on measuring is transferred to control signal the behavior of described the second characterization platform.

Method described in 14. claims 11, the wherein said behavior of determining the composition of at least a portion analyte in the second characterization platform comprises the behavior of the component of the analyte described in chromatographic isolation.

Method described in 15. claims 14, the method also comprises the behavior of the component of the analyte that detects chromatographic isolation.

Method described in 16. claims 14, the wherein said behavior of the composition of at least a portion analyte of determining in the second characterization platform also comprises the behavior of the chromatogram that produces the composition component that represents analyte.

Method described in 17. claims 16, the method also comprises the behavior that described chromatogram is transferred to remote equipment by well.

Method described in 18. claims 11, the method also comprises the measurement parameter based on from described the first characterization platform at least partly, the behavior that produces the first set operational factor of described the second characterization platform.

Method described in 19. claims 11, wherein said analyte is formation fluid.